Mineral Scale Deposition Research Articles

Effect of engineered water and scale inhibitor concentration on the adsorption performance of gypsum inhibitors on multi‐walled carbon nanotubes and crushed sandstone

AbstractEngineered waterflooding is an effective process for enhanced oil recovery, but it can lead to mineral scale deposition due to the incompatibility of brines. Previous studies on scale mitigation have mainly focused on high‐temperature baryte and anhydrite scales, neglecting gypsum precipitation and inhibitors adsorption at low temperatures. Additionally, earlier research has used simple brines that do not reflect the actual injection and formation water in reservoirs. In this study, the impact of temperature, various brine mixtures, and thermodynamic databases on saturation ratio and scale precipitation is explored using PHREEQC (pH‐REdox‐EQuilibrium‐C program). The study reveals that the copresence of calcium and magnesium ions improves the gypsum inhibition efficiency of scale inhibitors (SIs) at low concentrations to a maximum of 79%. However, this effect is reversed or neutral at higher SI concentrations. The study also shows that the presence of monovalent ions reduces the adsorption of SIs by multi‐walled carbon nanotubes (MWCNTs). Removing sodium ions from seawater while leaving calcium and magnesium ions intact increases MWCNTs' adsorption capability to 93%. This is because monovalent cations attach to the adsorbent surface and block the active sites, whereas divalent cations act as a bridge between MWCNT and SIs. The study establishes that the behaviour of SIs regarding adsorption on MWCNT and crushed sandstone depends on various factors, including molecule size, calcium toleration of the SIs, point of zero charge, and solution pH. Understanding these factors can improve the effectiveness of SIs, reduce chemical costs, and prolong the life of oil wells.

THE SIMULATION OF INTERMOLECULAR INTERACTIONS OF CARBOXYLIC AND AMINE GROUPS WITH CALCIUM CARBONATE

Surface facilities including tubing and valves at the oilfield have been plagued by mineral scale deposits, which are constitute of calcium carbonate (CaCO3). Penta-potassium diethylenetriaminepentaacetic acid salt (DTPA-K5) has a higher affinity for the metal cations complexes during the chelation process. The eight complexing sites (five carboxylate and three amines) empower the metal ion interactions. This work investigated the molecular dynamics simulations between the DTPA-K5 with the calcium carbonate, CaCO3 scale. The interaction was performed through molecular dynamic (MD) simulation using condensed phase optimised molecular potentials for atomistic simulation studies (COMPASS) force field and the Ewald summation method in Material Studio. The simulation trajectory files examined the intermolecular interactions for radial distribution function (RDF). The simulation shows strong DTPA-K5 with calcium interactions, which revealed the metal ion complexes contributing to the chelation process through the reactive carboxylic and amine functional groups, which were O7 == Ca at radius, r, 2.25 Å with g(r) of 10.09 and N1 -- Ca at radius, r, 2.25 Å with g(r) 2.51.

Gypsum scale formation and inhibition kinetics with implications in membrane system

Water desalination using membrane technology is one of the main technologies to resolve water pollution and scarcity issues. In the membrane treatment process, mineral scale deposition and fouling is a severe challenge that can lead to filtration efficiency decrease, permeate quality compromise, and even membrane damage. Multiple methods have been developed to resolve this problem, such as scale inhibitor addition, product recovery ratio adjustment, periodic membrane surface flushing. The performance of these methods largely depends on the ability to accurately predict the kinetics of mineral scale deposition and fouling with or without inhibitors. Gypsum is one of the most common and troublesome inorganic mineral scales in membrane systems, however, no mechanistic model is available to accurately predict the induction time of gypsum crystallization and inhibition. In this study, a new gypsum crystallization and inhibition model based on the classical nucleation theory and a Langmuir type adsorption isotherm has been developed. Through this model, it is believed that gypsum nucleation may gradually transit from homogeneous to heterogeneous nucleation when the gypsum saturation index (SI) decreases. Such transition is represented by a gradual decrease of surface tension at smaller SI values. This model assumes that the adsorption of inhibitors onto the gypsum nucleus can increase the nucleus superficial surface tension and prolong the induction time. Using the new model, this study accurately predicted the gypsum crystallization induction times with or without nine commonly used scale inhibitors over wide ranges of temperature (25–90 °C), SI (0.04–0.96), and background NaCl concentration (0–6 mol/L). The fitted affinity constants between scale inhibitors and gypsum show a good correlation with those between the same inhibitors and barite, indicating a similar inhibition mechanism via adsorption. Furthermore, by incorporating this model with the two-phase mineral deposition model our group developed previously, this study accurately predicts the gypsum deposition time on the membrane material surfaces reported in the literature. We believe that the model developed in this study can not only accurately predict the gypsum crystallization induction time with or without scale inhibitors, elucidate the gypsum crystallization and inhibition mechanisms, but also optimize the mineral scale control in the membrane filtration system.

Review of Phosphorus-Based Polymers for Mineral Scale and Corrosion Control in Oilfield.

Production chemistry is an important field in the petroleum industry to study the physicochemical changes in the production system and associated impact on production fluid flow from reservoir to topsides facilities. Mineral scale deposition and metal corrosion are among the top three water-related production chemistry threats in the petroleum industry, particularly for offshore deepwater and shale operations. Mineral scale deposition is mainly driven by local supersaturation due to operational condition change and/or mixing of incompatible waters. Corrosion, in contrast, is an electrochemical oxidation–reduction process with local cathodic and anodic reactions taking place on metal surfaces. Both mineral scaling and metal corrosion can lead to severe operational risk and financial loss. The most common engineering solution for oilfield scale and corrosion control is to deploy chemical inhibitors, including scale inhibitors and corrosion inhibitors. In the past few decades, various chemical inhibitors have been prepared and applied for scaling and corrosion control. Phosphorus-based polymers are an important class of chemical inhibitors commonly adopted in oilfield operations. Due to the versatile molecular structures of these chemicals, phosphorus-based polymeric inhibitors have the advantage of a higher calcium tolerance, a higher thermal stability, and a wider pH tolerance range compared with other types of inhibitors. However, there are limited review articles to cover these polymeric chemicals for oilfield scale and corrosion control. To address this gap, this review article systematically reviews the synthesis, laboratory testing, and field applications of various phosphorus-based polymeric inhibitors in the oil and gas industry. Future research directions in terms of optimizing inhibitor design are also discussed. The objective is to keep the readers abreast of the latest development in the synthesis and application of these materials and to bridge chemistry knowledge with oilfield scale and corrosion control practice.

Newly engineered alumina quantum dot-based nanofluid in enhanced oil recovery at reservoir conditions

In this work, a newly engineered alumina quantum dot-based nanofluid (α-AQDs; D ~ 4 nm; amorphous solid) and one commercial alumina nanoparticle-based nanofluid (γ-ANPs; D ~ 20 nm; crystalline type) with the capability of strong colloidal dispersion at reservoir conditions, such as, high salinity, divalent ions (Ca2+) and high temperature was compared. The main goal of this research was to study the crude oil displacement mechanisms of alumina suspensions as a function of variety in size and particle morphology in aged carbonate rocks. The strong interaction potential between the particles was achieved by the citric acid and a special composition of a carboxylate-sulfonate-based polyelectrolyte polymer as an effective dispersant compound on the surface, leading to a negative particle charges and an additional steric and electrostatic repulsion. Wettability alteration upon exposure to fluids using the contact angle and the Amott cell were performed on saturated carbonate plug samples and rock slices. While, dynamic core displacements were conducted to test the water/nanofluid/oil flow and nanoparticle retention behavior thorough typical pore throats underground the reservoir conditions. The stability results revealed that PE-polymer was able to create a long-term colloidal fluid during 30 days. It was found that mass concentration of nanofluid increased with decreasing in particle size. The optimal amount of particles in aqueous solution was obtained 0.05 wt% for ANPs, increased up to 0.1 wt% for AQDs. Analysis of experiments showed that wettability alteration was the main mechanism during nanofluid injection. Laboratory core-flooding data proved that the enhanced oil recovery due to a less concentration state by ANPs was consistent with AQDs at higher concentrations. In addition, permeability-impairment-behavior study was discussed in terms of possible mineral scale deposition and alumina release on the rock surface. Results showed that a large extent of permeability damage caused by mineral scale (55–59%). Alumina quantum dot-based nanofluids were found a minimum impairment (2–4%) and a significant reduction of ~ 10% in permeability was observed for ANPs-based nanofluid.

Scaling control by using ultrasonic guided waves

Fouling of heat exchanger surfaces is a major concern in the industry, resulting in performance losses through a decrease in the overall heat exchange coefficient. Control methods exist but are costly and have a strong environmental impact. Thus, the use of physical treatments is very promising, because the action is done on the clogged surface, in the bulk or in the solution. The present study shows the influence of ultrasonic guide waves on the crystallization of calcium carbonate inside a plate heat exchanger from scaled water. An experimental pilot was set up to study the scaling phenomenon. Several operating parameters such as flow rate, duration, and temperature were experimentally varied in order to identify their influence on the scale deposition in the heat exchanger. Subsequently, a thermodynamic prediction was performed by geochemical modeling using the Phreeqc software in order to get an idea of the nature of the deposit formed after the heating of scaled water. The main objective of this work was the determination of the impact of ultrasonic treatment on the mineral deposit, qualitatively and quantitatively. Therefore, four types of experiments lasting three days are presented in this paper to experimentally show the influence of ultrasound generated by a 35–50 kHz transducer on scale formation. The amount of solid deposited in grams/per day/area, the polymorphism of the formed crystals, and the number, size and size distribution of the particles were analyzed. Disassembly of the exchanger allowed access to the distribution of scale on the plates, and thus justified the choice of location for the 35–50 kHz transducer. It was also possible to estimate the thickness of the scale experimentally by 3D digital microscopy and to ensure the absence of microcrystals in the pores of the plate by analyzing the surface roughness. The results obtained were compared to the experimental measurements with and without the presence of the 35–50 kHz transducer. This allowed the evaluation of the effect of guided ultrasonic waves for the prevention of scale deposits. The presence of a single medium power transducer reduced mineral scale deposition in a plate and gasket heat exchanger by 76%.

Simulation of Scale Inhibitor Squeeze Treatments in a Polymer Flooded Reservoir

Summary This study aims to demonstrate the changes to scale inhibitor squeeze lifetimes in a polymer flooded reservoir vs. a waterflooded reservoir. A squeeze campaign was designed for the base waterflood system, then injection was switched to polymer flooding (PF) at early and late field life. The squeeze design strategy was adapted to maintain full scale protection under the new system. During the field life, the production of water is a constant challenge. Both in terms of water handling, but also the associated risk of mineral scale deposition. Squeeze treatment is a common technique, where a scale inhibitor is injected to prevent the formation of scale. The squeeze lifetime is dictated by the adsorption/desorption properties of the inhibitor chemical, along with the water rate at the production well. The impact on the adsorption properties and changes to water rate on squeeze lifetime during PF are studied using reservoir simulation. A 2D 5-spot model was used in this study, which is considered a reasonable representation of a field reservoir under waterflooding (WF)/PF. It was observed that when applying polymer (HPAM) flooding, with either a constant viscosity or with polymer degradation. The study concludes that the number of squeeze treatments was significantly reduced as compared to the waterflood case. This is due to the significant delay in water production induced by the polymer flood. When the polymer flood was initiated later in field life, after 0.5 PV (reservoir PVs) water injection, resulting in 70% water cut approximately, the number of squeeze treatments required was still lower than the waterflood base case. However, it was also observed that in all cases, at later stages of field life the positive impact of PF on squeeze lifetime begin to diminish, due in part to the polymer breakthrough, which results in higher water viscosity in the production near-wellbore region. Preventing the overflush to be as effective transporting the scale inhibitor. This study represents the first coupled reservoir simulation/squeeze treatment design for a polymer flooded reservoir. It has been demonstrated that in over the course of a field lifetime, PF will in fact reduce the number of squeeze treatments required even with a potential reduction in inhibitor adsorption. This highlights an opportunity for further optimization and a key benefit of PF in terms of scale management, aside from the EOR.

Coreflood Effluent and Shale Surface Chemistries in Predicting Interaction between Shale, Brine, and Reactive Fluid

Summary Field and laboratory observations to date indicate that the efficiency of hydraulic fracturing, as it relates to hydrocarbon recovery, depends significantly on geochemical alterations to rock surfaces that diminish accessibility by partial or total plugging of the pore and fracture networks. This is caused by mineral scale deposition, such as coating of fracture surfaces with precipitates, particle migration, and/or crack closure, because of dissolution under stress. In reactive flow-through experiments, mineral reactions in response to acidic fluid injection significantly reduced system porosity and core permeability. The present study focuses on changes to fluid chemistry and shale surfaces (inlet and fracture walls) resulting from shale-fluid interactions and integrates these findings for an improved estimate of transport-related consequences. The pre- and post-reaction shale surfaces were examined by spatially resolved scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS) analysis. Importantly, inductively coupled plasma-mass spectrometry/optical emission spectroscopy (ICP-MS/OES) was utilized to probe the chemical evolution of the coreflood effluents. The three study cores selected from the Marcellus formation represent different mineralogies and structural features. In flow-through experiments, laboratory-generated brine and HCl-based fracture fluid (pH = 2) were injected sequentially under effective stress (up to 500 psi) at reservoir temperature (80°C). SEM-EDS results confirmed by the ICP concentration trends showed significant Fe hydroxide precipitates in the clay- and pyrite-rich outcrop sample because of partial oxidation of Fe-bearing phases in the case of intrusion of low salinity water-based fluids. Porosity reduction in the Marcellus Shale Energy and Environmental Laboratory (MSEEL) carbonate-rich sample is related to compaction of cores under stress because of matrix softening with substantial dissolution, and pore filling by hydroxides, as well as secondary barite and salts. Despite the same fluid compositions and experimental conditions used for both MSEEL samples, barite precipitation was much more intense in the MSEEL clay-rich sample because of its greater sorption capacity and additional sulfate source as well as its fissile nature with multiple lengthwise cracks. ICP tests revealed time-resolved concentration behavior in produced brine and reactive fluids that in turn complemented the pre/post-reaction SEM-EDS observations. The greatest release of metal ions into brine was in clay-rich systems indicating the importance of chemical compatibility between in-situ shale and nonequilibrated injection solutions. A thorough examination of surface and effluent data pointed to the substantial influence of formation brine in the shales, mixing of brine with fracture fluid during flow, and shale mineralogy on mineral dissolution and scale formation that significantly affect flow efficiency.

Отложение минеральных солей при использовании жидкостей глушения

Paper describes problems observed during clean-up & bean-up operations of one of the Western Siberia field wells. The problem consisted of an intensive mineral scale deposition in electrical submersible pump (ESP) impellers. This led to rapid ESP failure with “no flow” code. Main causes and mechanism of mineral scale deposition was determined, scale inhibitor and scale dissolver were selected based on laboratory tests, production chemicals application procedure was developed. It was shown that Zn2+ ions included in specific kill fluids compositioncould have significant impact on scale deposition rate. This shall be taken into account during scale management implementation in case of zinc-containing kill fluid use.

Новый подход к рентгенофазовому анализу минеральных отложений в нефтепромысловом оборудовании

Новый подход к рентгенофазовому анализу минеральных отложений в нефтепромысловом оборудовании

Green inhibitors reduce unwanted calcium carbonate precipitation: Implications for technical settings

Mineral scale deposits in water drainage and supply systems are a common and challenging issue, especially by clogging the water flow. The removal of such unwanted deposits is cost intensive arguing for case-specific and sustainable prevention strategies. In the present study, a novel on-site approach to prevent calcium carbonate (CaCO3) scale formation was assessed in two road tunnel drainages: Application of the eco-friendly green inhibitor polyaspartate (PASP) caused (i) a significant inhibition of CaCO3 precipitation, (ii) a more porous or even unconsolidated consistence of the deposits, and (iii) a shift from calcite to the metastable aragonite and vaterite polymorphs. Even relatively low PASP concentrations (1–33 mg/l) can significantly decrease CaCO3 scale deposition, removing up to ∼7 t CaCO3/year at an efficiency up to 84%. Application of PASP for water conditioning should also consider case-specific microbial activity effects, where consumption of PASP, e.g. by Leptothrix ochracea, can limit inhibition effects.

Nucleation and Crystallization Kinetics of Barium Sulfate in the Hydrodynamic Boundary Layer: An Explanation of Mineral Deposition

The initialization of barite deposition is believed to be mineral nucleation. The induction times characterizing the kinetics of nucleation have been widely studied to investigate the precipitation kinetics of barium sulfate and to estimate the risk of mineral deposition in the flowing tube. It is generally accepted that if the solution’s supersaturated solution’s induction time is longer than the pipe’s traveling time, barium sulfate will not precipitate inside the pipe. However, recent research shows that barium sulfate still deposits inside the flowing tube even though the predicted induction time is longer than the travel time. The results correlate to the field observations that the mineral scale deposition is found in the production well even at the condition that is predicted to be kinetically stable. The contradiction suggests that there is a missing step of mineral deposition in the flow. In this work, a hypothesis of nucleation in the boundary layer is proposed to explain the contradiction: the barium sulfate can nucleate inside the boundary layer at the surface where the linear flow velocity approaches zero. This slow-flow region offers enough time for the crystals to form without being flushed away. A series of experiments were conducted in the flowing tube and the microfluidic channels to support the hypothesis. The amounts of deposited barium sulfate in the pipes were measured and compared with the induction time prediction. The result shows that with barite SI (supersaturation index) = 0.5–0.9 at 120 °C, the barium sulfate can deposit all along the tube even when the predicted induction times are longer than the traveling time (311 s). On the other hand, the observed nucleation time in the microfluidic channels matches the previously reported nucleation time in the kinetic turbidity tests in beakers. This implies that the barium sulfate can stay and nucleate in the boundary layer at the surface, which further supports the proposed mechanism. To conclude, we combine the ideas of induction times, boundary layer, and precipitation kinetics to describe a new mechanism of barium sulfate deposition. Once the solution in the boundary layer reaches its induction time, the deposition begins.

Numerical modeling of CaCO3 mineral scale deposition in oil and gas production well taking into account the effect of fluid dynamics and chemical reaction kinetics

Mineral scale deposition (especially CaCO3) is a severe problem at many oil fields, in which the scale adheres to the inner surface of the production tubing and the pre-processing facilities causing significant reduction of flow rate and damage the production system. Recently, many researches have been conducted by oil and gas company in Vietnam to study this subject based on production data and experimental results using commercial software for example ScaleChem and ScaleSoftPitzer. The previous mentioned commercial software only uses thermodynamics approach without consider the effect of fluid dynamics and chemical reaction kinetics. Moreover, there is still a lack of intensive researches on the physical and chemical phenomena associated with CaCO3 mineral scale deposition. This paper presents the construction of an integrated model in which the mechanism of mineral scale deposition is fully characterized by not only thermodynamics but also fluid dynamics and chemical reaction kinetics. The developed model can be used to build CaCO3 scaling profile for oil and gas production wells.

A New Coupled Model for Permeability-Impairment Prediction Because of Mineral Scale Deposition in Water-Injection Wells

Summary It is common to produce some percentage of water during the oil-extraction process. Conventionally, some water-disposal wells are drilled in an oil field to inject these useless and hazardous waters. Mineral scale formation is a critical issue in water-injection wells and may result in well plugging and an injection rate decrease in these wells. The two steps of mineral scale formation are scale precipitation and scale deposition. Two main mechanisms of inorganic scale precipitation are incompatibility between injected water and reservoir formation water and changes in the thermodynamic state of injected water. The injectivity of the well decreases because of deposition of supersaturated precipitated scales through the well column and near-wellbore region. Currently, limited research has been done to evaluate inorganic scale deposition, and most of the research is limited to calculation of total scaling by commercial software. In this study, the mineral scale precipitation is evaluated by software modeling and laboratory experiments in an Iranian oil field, and the effect of the scale deposition phenomenon is assessed on permeability impairment and injection rate decrease. One of the major novelties of this work is simulation of various scale-deposition models by coupling MATLAB® software coding and a reservoir simulator. The accuracy of different deposition models is analyzed by comparing them with field data (real water-injection well) and laboratory tests (coreflooding test). Finally, our simulation results show that a single deposition model could not exactly predict the scaling phenomena in the studied carbonate reservoir that is supersaturated with CaCO3 and CaSO4. It is recommended to improve the scale-formation prediction with a mixed deposition model supported by reliable static/dynamic modeling and experimental analysis.

Review of Synthesis and Evaluation of Inhibitor Nanomaterials for Oilfield Mineral Scale Control.

Oilfield flow assurance is the subject to study the impact on the flow of production fluids due to physicochemical changes in the production system. Mineral scale deposition is among the top 3 water-related flow assurance challenges in petroleum industry, particularly for offshore and shale operations. Scale deposition can lead to serious operational risks and significant financial loss. The most commonly adopted strategy in oilfield scale control is the deployment of chemical inhibitors. Although conventional chemical inhibitors are effective in inhibiting scale threat, they have the drawbacks of short transport distance and limited squeeze lifetime due to their intrinsic chemical properties. In the past decade, as an alternative to conventional chemical inhibition, research efforts have been made to prepare functional nanomaterials with different chemical compositions to overcome the drawbacks of conventional chemical inhibitors. These synthesized nanomaterials can serve as delivery vehicles to deploy inhibitors into the target location in the production system. These nanomaterials are reported to have multiple advantages over the conventional inhibitors in terms of transportability, controlled release, and functionality, evidenced by a series of experimental studies. This review presents an overview of scale inhibitor nanomaterial development and the current methods to synthesize and to evaluate these nanomaterials in a systematic and comprehensive manner. This review focuses on the chemistry principles and methodologies underlying inhibitor nanomaterial synthesis and also the chemical instrument and strategies in evaluating the physiochemical properties of these materials in terms of inhibition effectiveness, transportability, and inhibitor return. The scale inhibitor nanomaterials (SINMs) presented in this review exemplify the continuous development in our capabilities in adopting novel nanotechnology in combating actual engineering challenges in petroleum industry.

Facile one-pot synthesis of metal-phosphonate colloidal scale inhibitor: Synthesis and laboratory evaluation

Mineral scale deposition is a serious flow assurance concern threatening the safety and integrity of oilfield operations. Subsurface and wellbore scale control is commonly managed by scale squeeze treatment. Compared to the conventional chemical inhibitor pill applied in a scale squeeze treatment, colloidal scale inhibitor materials are capable of enhancing inhibitor transportability in formation medium and extending squeeze lifetime. A number of functional scale inhibitor colloidal materials have been synthesized in the previous studies including the crystalline low solubility materials. However, these reported synthesis routes are complicated to follow, involving extensive experimental setup. In this study, a one-pot synthesis route has been presented to prepare metal-phosphonate colloidal inhibitor (MPCI) material in a facile and economical manner. This method is based upon a citrate-assisted approach where a low solubility MPCI material with 40 nm particle size can be produced. Laboratory transport experiment suggests that calcium-based MPCI can be transportable through sand medium at representative oilfield conditions with 100% breakthrough realized within 2.5 pore volumes in sand-packed column. Laboratory squeeze simulation tests indicate that this material is able to return inhibitor with a stable return concentration for an extended squeeze lifetime. The calculated normalized squeeze lifetime of calcium-based MPCI is as high as 1100 m3 kg−1 in sand medium. Magnesium and Zirconium based MPCI can increase the stabilized inhibitor return concentration up to 3 mg L−1. This study expands our understanding of the colloidal inhibitor materials and promotes the potential field application of such materials for oilfield scale squeeze treatment.

A reactive transport approach for modeling scale formation and deposition in water injection wells

Petroleum industry is moving toward enhancing oil recovery methods, especially water-based methods, including low salinity and smart water flooding which water with an optimized composition is injected into the reservoir for improving oil recovery. Injection of water into the target formation is also a common operation in geothermal energy production. As the water is being injected into the reservoir, pressure and temperature change along the well column and cause scale formation. Mineral scale precipitation and deposition is a common problem for water injection wells which reduces the effective radius of the wellbore and affects the injection efficiency.In this paper, modeling scale precipitation and deposition in a pipe flow system by coupling of species transport model and a geochemical software package (PHREEQC) is investigated. The results of the proposed method were matched with experimental data. The model has been used for prediction of scale precipitation and deposition profile along with water injection wells during low salinity waterflooding. The results show deposition of calcium carbonate scale in the bottom section of the water injection wells. Higher temperature, higher salinity and more rate fluctuation cause an increase in scale precipitation and deposition in the wellbore condition.

Laboratory investigation of co-precipitation of CaCO3/BaCO3mineral scale solids at oilfield operating conditions: Impact of brine chemistry

Oilfield mineral scale deposition can become severe flow assurance challenge especially for offshore deepwater productions. Hazards arising from scale formation and subsequent deposition include production system throughput reduction and eventually blockage. Among various types of scales, carbonates are among the most frequently observed scales in oilfield operations. Similar to many natural and industrial processes, co-precipitation of multiple scales can commonly be observed in oilfield operations. Although extensive research efforts have been made in the domain of understanding the thermodynamics of scale formation, there are limited studies to investigate the kinetic aspect of scale formation, particularly the kinetics of co-precipitation of multiple scales. In this study, the kinetic characteristics of CaCO3/BaCO3co-precipitation have been experimentally investigated at representative oilfield conditions of 80 °C and 1 M NaCl condition. The focus was given to the investigation of the impact of different brine chemistry conditions such as mineral saturation level and Ca to Ba molar ratio. The experimental results suggest that CaCO3saturation level, substrate material and molar ratio can impact the nature and morphology of the carbonate scales formed. An elevation of CaCO3saturation index from 0.6 to 2 will change the formed carbonate solids from calcite to aragonite. In addition, at a Ca:Ba molar ratio of 1:15 with an excessive aqueous Ba species available, Ba species can partition into CaCO3crystal lattice to distort CaCO3lattice, resulting in almost 2-fold increase in aqueous Ca concentration. The results and conclusions from this study have the potential to benefit oilfield scale control strategy development, particularly the one related to carbonate scale formation control.

Use of rice straw-based biochar for batch sorption of barium/strontium from saline water: Protection against scale formation in petroleum/desalination industries

The formation of hard mineral scale deposits (e.g., celestite (SrSO4) and barite (BaSO4)) is the most common problem that hinders sustainable operations of water-flooded oilfield and desalination systems (i.e., membrane fouling) when using poor quality water contaminated with barium (Ba(II)) and strontium (Sr(II)) ions. In this work, nanoscale biochar (∼53–712 nm) was synthesized from waste rice straw (cost = 380 to 560 ± 27 US$/Ton; n = 9) and applied as a protective approach against the formation of mineral scale deposits via adsorptive removal of Ba(II)/Sr(II) contaminants from 30,000 ppm saline wastewater. Adsorption of Ba(II)/Sr(II) ions onto biochar was investigated and optimized as a function of biochar amount, water pH, contact time, temperature, and Sr(II)/Ba(II) ratio using response surface methodology. Based on kinetic and isotherm analyses, the biochar exhibited enhanced potential to capture Sr(II)/Ba(II) ions via weak ion-exchange or pore-filling mechanisms (sorption energy (E)≈ 0.61–0.89 kJ/mol). A comparison of partition coefficient (PC) values verified that sorption of Sr(II) onto biochar is far superior to that of Ba(II) (PCs of 10.1 and 2.5 μmol g−1 μM−1, respectively). Sorption selectivity was mainly dependent on solution pH and the metallic properties of Ba(II)/Sr(II)(e.g., metal size, speciation, and mobility). Quantitative analysis of treated saline water using electrical conductivity and ion chromatography confirmed the ability of biochar sorbent to remove Ba(II) and Sr(II) ions (97.5%) with pre-desalination (e.g., total salts reduction of 25.7% after 48 h). It is thus recommended to utilize the prepared biochar as a promising pre-desalinating adsorptive medium to inhibit mineral scale formation before oilfield water flooding in the petroleum field and membrane desalination systems.

The Mechanism of Barium Sulfate Deposition Inhibition and the Prediction of Inhibitor Dosage

Scale inhibitors are widely used to prevent mineral scale deposition and precipitation in industrial processes. In this study, the performance of scale inhibitors is systematically investigated in ...