Polymeric Scale Inhibitors Research Articles

Synthesis, characterization, and performance evaluation of AA/AMPS copolymers with different molecular weights and explanation of the inhibition mechanism of calcium carbonate and calcium sulfate

Polymeric scale inhibitors are widely acknowledged for their eco-friendliness, strong compatibility, and versatile nature. However, the impact of molecular weight variation on their inhibitory efficacy remains a relatively understudied aspect. In this investigation, AA/AMPS copolymers with distinct molecular weights (1000, 2000, 3000, 4000, 5000, 6000) were synthesized and probed for their influence on mineral scale inhibition across diverse water quality parameters (e.g., calcium ion concentration, pH) and process conditions (e.g., temperature, duration). Concurrently, the crystalline and morphological alterations of AA/AMPS during mineral scale inhibition were delved. By integrating molecular dynamics simulations and quantum chemical calculations, the effects of varying molecular weights of AA/AMPS on mineral scale inhibition were scrutinized. Moreover, the inhibition mechanism was thoroughly explored. Our findings revealed that AA/AMPS with molecular weights of 2000 and 3000 exhibited superior inhibition efficacy against calcium carbonate and calcium sulfate. This phenomenon was attributed to the movement velocity and binding energy of AA/AMPS with corresponding molecular weights towards the primary crystal growth surface. Additionally, the carboxyl oxygen atoms on the polymers facilitated chelation with calcium ions, thereby impeding further crystal formation and growth. Consequently, achieving heightened efficiency in scale inhibition.

Sustainable Calcite Scale Inhibitors via Oxidation of Lignosulfonates.

Deposition of inorganic scales in wells, flow lines, and equipment is a major problem in the water treatment, geothermal, or upstream oil and gas industries. Deployment of scale inhibitors has been adopted worldwide for oilfield scale prevention. Commercial synthetic scale inhibitors such as polymeric carboxylates and sulfonates or nonpolymeric phosphonates offer good scale inhibition performance but often suffer from one or more limitations including biodegradability, calcium compatibility, and thermal stability. Lignin-based biomaterials such as sodium lignosulfonates are natural, sustainable, and widely available polymers that are accepted for use in environmentally sensitive areas. Here we show that, although lignosulfonates perform relatively poorly as calcite scale inhibitors in dynamic tube blocking tests, oxidized lignosulfonates show a much improved inhibition effect by a factor of 20-fold. The oxidized lignosulfonates are easy to prepare in a 1-step reaction and show excellent calcium compatibility and thermal stability, useful for downhole squeeze treatments in high temperature wells. This present study unequivocally establishes oxidized lignosulfonates as a new class of sustainable green scale inhibitors, thereby bridging the gap between materials derived directly from nature and the classic synthetic polymeric scale inhibitors.

Synthesis and evaluation of a new polymeric scale inhibitor with multiple scale inhibition properties

In this article, the monomers epoxy succinic acid (ESA) and maleic acid ethanolamine (PTA) were prepared, and then the terpolymer scale inhibitor P(ESA-AA-PTA) was synthesized by aqueous solution polymerization using ESA, PTA, and acrylic acid (AA) as monomers. The structures of the synthesized monomers and polymers were characterized by FTIR. The optimum synthesis conditions of the terpolymer were obtained by static scale inhibition experiment, and the effects of the amount of scale inhibitor, test temperature, test time, and solution pH on the inhibition performance of the four scales, CaCO3, CaSO4, BaSO4, and SrSO4, were discussed. The results showed that the best CaCO3 scale inhibition efficiency was 85% when the molar ratio of ESA:AA:PTA was 1:1:0.5, the initiator dosage was 10 wt%, the polymerization time was 3.5 hours and the polymerization temperature was 95 °C. In the optimum water environment, the scale inhibition efficiency of CaCO3 scale and CaSO4 scale reached 100%, BaSO4 scale could reach 75% and SrSO4 scale could reach 54%. P(ESA-AA-PTA) had better scale inhibition properties than the majority of commercially available oilfield scale inhibitors. SEM and XRD results showed that the addition of P(ESA-AA-PTA) scale inhibitor hindered the growth of crystals and made the microscopic morphology of scale samples changed.

Preparation and Laboratory Testing of Polymeric Scale Inhibitor Colloidal Materials for Oilfield Mineral Scale Control.

Mineral scale refers to the hard crystalline inorganic solid deposit from the water phase. Although scale formation is very common in the natural environment, deposited scale particles can seriously threaten the integrity and safety of various industries, particularly oilfield productions. Scale deposition is one of the three most serious water-related production chemistry threats in the petroleum industry. The most commonly adopted engineering approach to control the scale threat is chemical inhibition by applying scale inhibitor chemicals. Aminophosphonates and polymeric inhibitors are the two major groups of scale inhibitors. To address the drawbacks of conventional inhibitors, scale inhibitor colloidal materials have been prepared as an alternative delivery vehicle of inhibitors for scale control. Quite a few studies have reported on the laboratory synthesis and testing of scale inhibitor colloidal materials composed mainly of pre-precipitated metal-aminophosphonate solids. However, limited research has been conducted on the preparation of polymeric inhibitor-based colloidal materials. This study reports the synthesis approach and laboratory testing of novel polystyrene sulfonate (PSS) based inhibitor colloidal material. PSS was selected in this study due to its high thermal stability and calcium tolerance with no phosphorus in its molecule. Both precipitation and surfactant surface modification methods were employed to prepare a barium-PSS colloidal inhibitor (BaPCI) material with an average diameter of several hundred nanometers. Experimental results indicate that the prepared BaPCI material has a decent migration capacity in the formation medium, and this material is superior to the conventional PSS inhibitor in terms of inhibitor return performance. The prepared novel BaPCI material has a great potential to be adopted for field scale control where environmentally friendly, thermal stable, and/or calcium tolerating requirements should be satisfied. This study further expands and promotes our capacity to fabricate and utilize functional colloidal materials for mineral scale control.

Method Measures Effective Scale-Inhibitor Concentration at Low Detection Limit

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209503, “A Fast and Accurate Method for Scale-Inhibitor Effective Concentration Measurement With Low Detection Limit,” by Xin Wang, Rice University; Zhaoyi Dai, SPE, China University of Geosciences; and Saebom Ko, Rice University, et al. The paper has not been peer reviewed. _ The accurate measurement of residual scale-inhibitor concentration in produced brine is essential for scale prevention. However, these scale inhibitors are effective at substoichiometric concentrations in most production conditions. It is difficult to measure such low inhibitor concentration with traditional methods, especially for non- or low-phosphorous polymeric scale inhibitors. In the complete paper, an assay method is developed to determine effective scale-inhibitor concentration. The presented assay method is quick, robust, and accurate, with a relative error of less than 10% even at 1 mg/L of inhibitor. Experimental Setup and Methods Brine Chemistry Inhibitor (BCIn) Continuous-Stirred-Tank Reactor (CSTR) Method. The schematic of the BCIn CSTR testing apparatus is shown in Fig. 1. The original supersaturated solution (OSS) with a designated barite scale inhibitor is injected into the reaction vial with no head space. This OSS may contain zero or a certain amount of scale inhibitor, and it will be stirred continuously and kept at room temperature during the whole test period. At Time 0, the cation titrant solution (TC) and the anion titrant solution (TA) start to be pumped continuously into the reaction vial with the same flow rate by using two syringe pumps. A green laser beam (with a wavelength of 532 nm) is shone through the reaction vial; light intensity is recorded continuously as current by using a multimeter with a photodiode detector in real time. The time between Time 0 and the solution turbidity change, which is detected as current drop, is defined as the critical time. Without the supply of scale inhibitor from the TC and TA solutions, the inhibitor concentration in the reaction vial decreases exponentially and the inhibitor concentration at Time t can be calculated. With continuous dilution of the inhibitor and continuous supply of the barite supersaturated solution in the reaction vial by TC and TA solution, the small nuclei and crystals begin to accumulate in the reaction vial, resulting in a turbidity change detected by the laser at the critical time. Because of the exponential decrease of the scale inhibitors, it is observed that, with the same solution composition and residence time, critical time increases linearly with the initial concentration of inhibitor. A series of tests is designed to match the composition of target brine with different amounts of scale inhibitors. The standard curve can then be developed. For the brine with an unknown amount of scale inhibitor, the inhibitor concentration can be calculated from the measured critical time. The known-additions method also can be used to determine the unknown inhibitor concentration in a sample. This process, and its associated equations, is provided in the complete paper, as is sample pretreatment.

The Effect of Blending Polymeric and Phosphonate Scale Inhibitors on Fluid/Fluid and Rock/Fluid Interactions: A Comprehensive Experimental and Theoretical Study

Summary Using seawater or engineered water to inject into oil formations can cause inorganic scaling, such as calcium sulfate, barium sulfate, and strontium sulfate. These scales may clog pore throats and limit production. Scale inhibitor (SI) squeeze treatment reduces inorganic scaling and improves oil recovery. Chemical compounds called SIs suppress or delay mineral scaling. SIs fall into two categories, each with its own mechanism. Most polymeric inhibitors impede nucleation, whereas phosphonate SIs deform crystal formation. The oil and gas industry now uses a fixed mixture of these inhibitors to maximize all inhibition mechanisms. However, the impact of blended SIs on fluid/fluid and rock/fluid interactions has not been addressed. This study aims to evaluate the efficiency of blended SIs when dealing with three well-known mineral scales all together. In this study, first, the process of mineral scale formation was simulated using PHREEQC (pH-REdox-EQuilibrium), and the impact of temperature and mixing ratios was investigated. Then, by choosing a proper temperature and mixing ratio, the effect of polymeric and phosphonate SIs blending on barium, calcium, and strontium sulfate inhibition is examined. Additionally, fluid/fluid interactions and rock/fluid interactions were studied via interfacial tension and contact angle measurements. The influence of seawater mixing ratio on calcium, strontium, and barium sulfate saturation indices is medium, low, and very low, respectively, but the effect on the amount of scale precipitation is very high, high, and low for the scales indicated. This adds to the fact that barium takes precedence in scale formation, and its presence may affect the other two scales, but calcium ions have barely any effect on barite formation. Moreover, the results show a positive synergistic effect of SIs blend on sulfate scale mitigation. However, this positive figure completely depends on the concentration of phosphonate SI for calcium and strontium sulfate, while the positive synergy exists at all concentrations of phosphonate SIs for barium sulfate. Moreover, SIs could lower the water/oil/rock contact angle by 10° on average and make it more water wet. Same enhanced results have been achieved for interfacial tension by adding SIs, reducing by 8 dynes/cm on average. It is worth noting that the interfacial tension and contact angle measurements are unaffected by the synergistic action of SIs mixing. The results of coreflooding experiments substantiate the effectiveness of SIs and show 8 and 45% permeability reduction for injection of seawater with and without SIs on two different core samples, respectively. For the first time in a sulfate scaling system, this work investigates the copresence of barite, celestite, and anhydrite against a wide range of blending SI concentrations. Based on the results, it is derived that the presence of all three sulfate scales undoubtedly affect the quantity of each scale’s precipitation and the efficacy of SIs.

A New Kinetic Assay Method for Effective Scale Inhibitor Concentration Determination with Low Detection Limit

Summary Scale inhibitors are widely used for mineral scale control in various industries, including oil and gas productions, geothermal energy acquisitions, and heat exchanger scale control to mention a few. In most applications, these scale inhibitors are effective at substoichiometric concentrations (e.g., 1 mg/L or lower), and the optimization of these applications is based on the ability to accurately measure the effective inhibitor concentration at such low concentrations. For example, the continuous treatment injection rate, the squeeze treatment frequency, or the batch treatment schedule need to be optimized to ensure the minimum inhibitor concentration (MIC) is achieved during production. However, the non- or low-phosphorous polymeric scale inhibitor concentration determination is difficult using inductively coupled plasma (ICP)-optic emission spectroscopy/mass spectrometry or ion chromatography, especially at mg/L level concentrations due to their high detection limits. The recently developed hyamine method or high-pressure liquid chromatography (HPLC) method involves intensive labor and high costs. Furthermore, in the complex oilfield operational conditions, the presence of other chemicals (e.g., surfactants, biocides, and corrosion inhibitors), the potential degradation of scale inhibitors and the use of combination scale inhibitors require the measurement of effective scale inhibitor concentration, which cannot be accomplished by the traditional methods. In this study, a new kinetic assay method has been developed to determine the effective scale inhibitor concentration with limits of detection (LODs) less than or around 0.1 mg/L for most cases. This method uses a continuous stirring tank reactor (CSTR) apparatus and is developed based on the linear correlation between the effective inhibition concentration and the measured critical time when laser signal changes. The results show that the inhibitor concentrations of various non- or low-phosphorous polymeric scale inhibitors in synthetic field brine, laboratory solutions, and real oilfield brines can be accurately determined at mg/L level, or lower, with less than 10% error. The method is robust, accurate, and much less time- or labor-consuming than other existing methods especially for non- or low-phosphorous polymeric scale inhibitors.

Evaluation of different polymeric scale inhibitors for oilfield application

The current challenges in oil production involve increase in productivity for high temperature, pressure and salinity conditions. Specifically, for flow assurance, scale inhibitors injection plays a key role to control scale formation. In this work, homopolymers were synthesized by free radical solution polymerization using sulfonate monomers as sodium styrene sulfonate (NaSS), 2-acrylamido-2-methyl-propanesulfonic acid (AMPS) and sodium vinyl sulfonate (SVS); phosphonic monomer as sodium vinyl phosphonic acid (VPA) and carboxylic monomer as sodium acrylic acid (AA). The homopolymers were characterized by 1H-NMR and SEC. The influence of the chemical structure and molecular weight of the polymers on scale inhibition process at different scenarios with high electrolyte concentration was evaluated by static and dynamic efficiency. AA and VPA polymeric scale inhibitors showed mainly effectiveness at short time (involved on nucleation mechanism) for barium and calcium sulfate, presented efficiency higher than 80%. NaSS homopolymers demonstrated higher efficiency (near to 75%) over time, comparing with other homopolymers specially in a multiple scale condition which presents high ionic forces (more than 200.000 ppm of total solids dissolved). These data suggest that NaSS polymeric inhibitor can act in different stages involved on scale inhibition, like as retarding nucleation, crystal modification and charge neutralization. It was observed that the best results were obtained using homopolymers from NaSS with number average molecular weight near to 13,000 Da.

A review: the utilization potency of biopolymer as an eco-friendly scale inhibitors

Scale formation is one of the major issues in the petroleum industry. The development of these scale layers could result in production losses and equipment instability because of pipeline blockage, energy leakage, corrosion acceleration and severe accidents which will impact the safety of the production process. The utilization of chemical scale inhibitors (SIs) is considered an economical and successful route for the scale prevention. Two main components of the chemical SIs are phosphonate and polymer. Many of the phosphorous compounds are toxic and very expensive. Besides, portions of the phosphonate compounds are thermally less stable than polymeric scale inhibitors in a harsh environment of high temperature and high pressure (HTHP). This is considered as an issue as a good scale inhibitor should be able to be applied under wide range of temperature and pressure. Therefore, the continuous development in petroleum production imposes the need to develop a novel phosphorus-free scale inhibitor. Meanwhile, polymers have been broadly applied as a scale inhibitor in oil and gas fields because of their enhanced thermal stability and improved environmental compatibility. Polymeric scale inhibitors also show better dispersing efficiency. Today, the biopolymers have pulled in a tremendous consideration from the industry to replace the utilization of synthetic polymer due to their interesting qualities such as their lightness, strong mechanical properties, and appealing functionality. Biopolymers are insensitive toward brine salinity yet are vulnerable to biological degradation. Specifically, these polymers present enormous potential for environmental application because of their biodegradability, chemical adaptability and reactivity, biocompatibility, and nontoxicity. Recently, several new eco-friendly scale inhibitors have been reported in the literature. Hence, this paper provides a review of the utilization of biopolymer as scale inhibitor in the application of oil and gas industry under laboratory approach or field trial application. The types of scales, chemical scale inhibitors (SIs) and biopolymers are likewise reviewed here. The presented work in this paper is expected to enhance the fundamental understanding of scale formation, as well as contribute to the development process of biopolymer scale inhibitors.

A Game Changer in Scale-Squeeze Technology

Background Field trials using a new scale-inhibitor technology that improves treatment lifetime of scale squeezes have been successfully performed in the Gulf of Mexico. Tomson Technologies, in partnership with Shell, developed proprietary nanoparticle carriers that enhance scale-inhibitor adsorption to the reservoir and control the return rate for extended periods of time. This technology results in less chemical bleed off in the initial flowback and increases the chemical retained in the reservoir, allowing for more effective squeeze treatments. Both nanoparticle-enabled phosphonate and polymer inhibitors have now been developed and successfully squeezed in the field. Phosphonate inhibitors are widely used for squeeze treatment due to their desirable adsorption and release properties in carbonate and sandstone reservoirs. Minor changes have been made to the chemistry, but overall, the fundamentals have remained unchanged for decades. Polymeric scale inhibitors have also been developed for cases in which phosphonates are not applicable. The nano-enhanced technology provides a large improvement of treatment lifetime of 2 to 4 times (200-400%) when compared to incumbents, making this technology advancement attractive even in cases where current squeezes are considered successful. The well selected for this case study is an offshore formation with a predominantly sandstone mineralogy (approximately 80% quartz) with 25-30% porosity and bottomhole temperature of 183°F (83°C). Technology From the Lab to Field A sandpack sample from the trial well was used in the laboratory to deter-mine the adsorption and desorption properties of the nano-enabled inhibitor in realistic rock conditions. Multiple conditioning steps were used before product was injected in a sequence that mimicked field squeeze treatments. Mass-balance results from the sandpack experiment show adsorption of approximately 8 mg of polymer retained per gram of crushed reservoir rock used in the experiment. A typical rule of thumb for phosphonate-scale inhibitors (only as a comparison since this is a polymeric scale inhibitor) is 1-2 mg of inhibitor retained per gram of rock. Therefore, this is considered a large improvement on adsorption. There are challenges associated with measuring polymers in brine as residuals; however, multiple methods, both in-house and external, were com-pared to ensure accuracy. The results using the nano-enhanced scale inhibitor show concentrations higher than 1 mg/L of active polymer for over 7,000 pore volume of return in the sandpack experiment. Complete intact core experiments were also conducted with reservoir fluids and showed no formation damage during the injection of the product with regained oil permeability of 96%. Oil permeability was in the 150-200 mD range for the intact core experiments. Third-party coreflood testing was performed with nitrified and foamed stages to ensure compatibility with the nano-enabled chemistry. No formation damage was observed with the nitrification of the stages containing the nano-enabled chemistry. Field Application Case Study After extensive lab validation of the product and supporting corefloods to de-risk the technology, Well A was selected by Shell to be the first well treated with the new nano-enabled extended-lifetime inhibitor.

Experimental Investigation of Water Incompatibility and Rock/Fluid and Fluid/Fluid Interactions in the Absence and Presence of Scale Inhibitors

SummaryWaterflooding is known as an affordable method to enhance oil recovery after primary depletion. However, the chemical incompatibility between injected water and the water in the reservoir may cause the formation of mineral scales. The most effective method for managing such a problem is to use a variety of scale inhibitors (SIs) along with a waterflooding plan. It is necessary to perform a comprehensive study on the incompatibility scaling issue for the candidate-brine/SI formulations, and also their effect on the reservoir-rock/fluid characteristics. In this study, both in the absence and presence of polymeric, phosphonate, and polyphosphonate SIs, the scaling tendency (ST) of different brines is evaluated through experimental and simulation works. Drop-shape analysis (DSA), environmental-scanning-electronic-microscopy (ESEM) observation, energy-dispersive X-ray (EDX) analysis, and microemulsion phase behavior are also used to study the effect of different brine/SI formulations on the rock/fluid and fluid/fluid interactions, through wettability and interfacial-tension (IFT) evaluation. In summary, sulfate (SO42−) was identified as the most problematic ion in the formulation of injected water that causes the formation of solid scales upon mixing with the cation-rich formation water (FW). In the case of SIs, solid precipitation was shifted toward a lower value, with more pronounced effects at higher SI concentrations. At different ionic compositions, the inhibition efficiency (IE%) of all SIs ranged from 16 to 50% at [SI] = 20 ppm and 38 to 81% at [SI] = 50 ppm. In general, phosphonates worked better (i.e., higher IE value) than polymeric SI. Measuring contact angles along with ESEM/EDX data also illustrated the positive effect of SIs on the wettability alteration of the aged carbonate substrates. In the absence of SIs, the contact angles for different brines were in the range of 70° ≤ θ ≤ 104°, whereas these values fell between 35 and 80° for systems containing 50 ppm of SI. In addition, phase-behavior study and IFT measurement illustrated a salinity-dependence effect of SIs on the interfacial behavior of the oil/water system.

Building a Fundamental Understanding of Scale-Inhibitor Retention in Carbonate Formations

Summary The development of effective scale-inhibitor (SI) squeeze treatments remains a challenge for carbonate reservoirs because of their substantial chemical reactivity with the SI. This in turn might potentially lead to uncontrolled SI precipitation and induced formation damage. This work takes a systematic approach to understanding the retention mechanisms of SI in carbonate formations with respect to the detailed carbonate-formation mineralogy, type of SI, and reservoir conditions in the absence of oil. Static adsorption/compatibility experiments, described previously as apparent adsorption tests (Kahrwad 2008), were performed to evaluate the areas of different retention mechanisms [pure adsorption (Γ) and coupled adsorption/precipitation (Γ/Π)] of different SI species in brine. Experiments were conducted for five SIs at various conditions: initial pH values, mineralogical compositions (calcite, limestone, and dolomite), and temperatures. The SI species used in this study included a phosphonate [di-ethylene tetra-amine penta (DETPMP)], a phosphate ester [polyhydric alcohol phosphate ester (PAPE)], and three polymeric SIs [polyphosphino carboxylic acid (PPCA), P-functionalized copolymer (PFC), and sulfonated polyacrylic acid copolymer (VS-Co)]. All precipitates were studied using environmental scanning electron microscopy/energy dispersive X-ray (ESEM/EDX) and particle-size analysis (PSA). The overall results from these coupled Γ/Π experiments are as follows: For the polymeric SIs (PPCA, PFC, and VS-Co), the highest retention levels were observed at low pH for all carbonate substrates, because of the increase in divalent cations calcium and magnesium (Ca2+ and Mg2+, respectively) available from rock dissolution for SI–M2+ ions (divalent cations) precipitation. For DETPMP and PAPE SIs, the retention level was greatest at higher pH values, because the SI functional groups were more dissociated and, hence, available for complexation with M2+ ions. The polymeric VS-Co predominantly showed pure adsorption with only a low amount of precipitation (Γapp ≈ 1.2 mg/g) in contact with the dolomite substrate. This is because of the presence of sulfonate groups (low pKa). For polymeric inhibitors, the retention level (Γapp) was highest on calcite (highest relative calcium content), followed by limestone and dolomite. DETPMP and PAPE SIs showed the highest retention levels on dolomite (higher final solution pH and more SI dissociated), followed by limestone and calcite. For all SI species, higher retention (more precipitation, Π) was observed at elevated temperatures. At lower temperatures, an extended region of pure adsorption was observed for all SIs. The information presented in this study will be helpful in SI product selection on the basis of mineralogy and reservoir conditions. As a consequence, longer squeeze lifetimes and improved efficiency of SI deployment in carbonate reservoirs can be achieved. In addition, this study provides valuable data for validating models of the SI/carbonate/Ca/Mg system that can be incorporated into squeeze design simulations.

The Effect of pH and Mineralogy on the Retention of Polymeric Scale Inhibitors on Carbonate Rocks for Application in Squeeze Treatments

Summary The bulk “apparent-adsorption” behavior (Γapp vs. Cf) of two polymeric scale inhibitors (SIs), polyphosphino carboxylic acid (PPCA) and phosphorus-functionalized copolymer (PFC), onto carbonate mineral substrates has been studied for initial solution pH values of 2, 4, and 6. The two carbonate minerals used, calcite and dolomite, are much more chemically reactive than sandstone minerals (such as quartz, feldspars, and clays), which have already been studied extensively. In nearly all cases, precipitates formed at higher SI concentrations were caused by the formation of sparingly soluble SI/calcium (Ca) complexes. A systematic study has been performed on the SI/Ca precipitates formed by applying both environmental scanning electron microscopy energy-dispersive X-ray (ESEM-EDX) analysis and particle-size analysis (PSA), and this identifies the morphology and the approximate composition of the precipitates. For PPCA, at all initial solution pH values, regions of pure adsorption (Γ) (PPCA < 100 ppm) and coupled adsorption/precipitation (Γ/Π) are clearly observed for both calcite and dolomite. PFC at pH values of 4 and 6 also showed very similar behavior, with a region of pure adsorption (Γ) for PFC < 500 ppm and a region of coupled adsorption/precipitation (Γ/Π) above this level. However, the PFC/calcite case at pH = 2 showed only pure adsorption, whereas the PFC/dolomite case at pH = 2 again showed coupled adsorption/precipitation at higher PFC concentrations. For the SIs on both carbonate substrates, precipitation is the more dominant mechanism for SI retention than adsorption above a minimum concentration of approximately 100 to 500 ppm SI. The actual amount of precipitate formed varies from case to case, depending on the specific SI, the substrate (calcite/dolomite), and the initial pH (pH = 2, 4, and 6). Although the qualitative behaviors of both PPCA and PFC were similar on both carbonate substrates, the apparent adsorption of PPCA was higher on calcite than on dolomite, and the apparent adsorption of PFC was higher on dolomite than on calcite. We discuss here how these observations are related to the reactivity of the different carbonate minerals, the resulting final pH (which affects the dissociation of the SI), the Ca-SI binding, and the solubility of the resulting complex.

Measurement and calculation of polymeric scale inhibitor concentration in water

Measurement and calculation of polymeric scale inhibitor concentration in water

The performance of a polymaleic-based polymeric scale inhibitor on CaCO3 inhibition under different water quality variables

The performance of a polymaleic-based polymeric scale inhibitor on CaCO3 inhibition under different water quality variables

Phosphino-polycarboxylic acid modified inhibitor nanomaterial for oilfield scale control: Synthesis, characterization and migration

Abstract A facile synthesis approach is reported to prepare scale inhibitor nanomaterial for oilfield scale control. The presence of a polymeric scale inhibitor can considerably change the morphology of the nanomaterial with a reduced particle size and an enhanced particle stability. In addition, the presence of electrolyte and sonication methods can impact the morphology and stability of the nanomaterial as well. Laboratory transport experiments suggest that the inhibitor nanomaterial has the future potential for oilfield mineral scale control. This is the first report of the synthesis and characterization of a template-free scale inhibitor nanomaterial combining both phosphonate and polymeric scale inhibitors.

Technology Focus: Oilfield Chemistry (September 2016)

Technology Focus In years past, analytics in the oil field meant running iron and manganese counts to determine corrosivity in a system or measuring a phosphorous residual to determine a phosphonate scale-squeeze chemical-flowback profile. Today, this is a given and the techniques used to perform this can be found in most, if not all, technical service laboratories or even can be implemented directly in the field. In the past decade, analytics in the oil field has grown to be a major discipline, integrally supporting the application of many different types of production chemicals and becoming viewed by some as a technology differentiator. We are all aware of inductively coupled plasma spectroscopy and how it can determine the full cationic content of a produced water. I am sure, however, that not everyone is aware of the expanse of techniques now available to determine the presence of multiple chemistries in a single commingled produced-water sample. As field developments become more and more complex, the need for differentiated analytical techniques becomes increasingly pronounced. Imagine the scenario in a deepwater production system where several wet trees tie into a common manifold and flow through a single flowline to a host facility. Each of the wells can be treated with a scale squeeze treatment of different chemistry, and techniques are now available to distinguish between these similar species. Bear in mind also that this situation can be complicated by the presence of additional chemistries injected into the flowline such as a further scale inhibitor, corrosion inhibitor, hydrate inhibitor, and paraffin or asphaltene inhibitor. The featured papers summarize some of the state-of-the-art techniques in use today to quantify production-chemical content accurately and reliably and therefore manage the flow-assurance risks. These techniques include advanced high-pressure liquid chromatography coupled with mass spectrometry and time-resolved fluorescence. Many of these techniques have been available for some years, but use in the oil field was complicated by the high salt content and presence of other contaminants such as dissolved organics and acids. This has required a significant advancement in pretreatment techniques for the fluids being analyzed, such as selective-ion and desalination cartridges. Readers are encouraged to research the suggested additional reading and take some time to delve into the references contained in these papers. This literature contains an extensive review of the history and current state of the art of analytical science for the oilfield chemist and engineer. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 179908 Accurate Detection of Tagged Polymeric Scale Inhibitors in Oilfield Produced-Water Samples by Vesa Vuori, Kemira Oyj, et al. SPE 179902 New Robust Analytical Development for Sulfonated Polymers in Oilfield Brines by Kirsty MacKinnon, Scaled Solutions, et al. SPE 173744 Application of Advanced Mass-Spectroscopy Techniques for Improved Scale Management in Conventional and Subsea Fields by Steve Heath, DONG Energy, et al. SPE 173712 Alkalinity in the 21st Century: An Improved Methodology for Carbonate Determination in Oilfield Brines by Russell A. Fisher, Baker Hughes, et al.

The Use of PPCA in Scale-Inhibitor Precipitation Squeezes: Solubility, Inhibition Efficiency, and Molecular-Weight Effects

Summary Phosphino polycarboxylic acid (PPCA) is an industry standard polymeric scale inhibitor (SI) that is often applied as a precipitation-squeeze treatment. In this phase-separated process, PPCA forms a sparingly soluble complex with calcium ions. We show that the solubility of the precipitated complex is rather different than the stock (“as supplied”) PPCA. We examined important properties such as its inhibition efficiency (IE) and its response in assay [by inductively coupled plasma (ICP) spectroscopy or wet-chemical methods], which are all understood in terms of the molecular-weight distributions (MWDs) of the various species involved in the precipitation squeeze. Our findings on the MWD effects have relevance not just in determining the concentration of the polymer in the return curve (PPCA), but also in its ability to prevent scale formation (i.e., its IE in the PPCA return curve), and they have implications for how the process should be modeled correctly. We study the MWDs of PPCA in great detail along with the solubility behavior of the PPCA_Ca complex, which plays an important role in precipitation-squeeze treatments. We describe several novel findings on the solubility of the (PPCA_Ca) complex system. Specifically, the precipitated complex was isolated and its solubility was determined experimentally in various brine compositions and as a function of temperature. MWDs were determined for the various fractions of PPCA. The solubility of the precipitated PPCA_Ca complex becomes lower as it is exposed to successive fresh supernatant brine, and the behavior is very unlike that expected from a “solubility product” model. However, by being able to carry out MWD experiments on the various PPCA species, a fairly complete understanding is being generated. This has led to the proposal of the “stripping” model of dissolution for the precipitated complex of PPCA. We believe that these results are the most detailed to be published in the literature on the PPCA system and that they are of particular significance and application for all polymeric SI precipitation-squeeze treatments. The relevance of these results for field precipitation-squeeze treatments is also discussed.

Barite-Scaling Risk and Inhibition at High Temperature

Summary Barite (BaSO4) is one of the common scales in oil-and-gas production. Extensive work has been conducted to study barite nucleation and inhibition at temperatures below 100°C. However, with the advance in deepwater exploration and production (E&P) which can encounter high-temperature (HT) conditions, a better understanding of barite-scaling risk at HT (e.g., > 150°C) becomes essential. In this paper, a systematic study was conducted to explore barite nucleation kinetics from 70 to 200°C in synthetic brines containing phosphonate (0–10 ppm) or polymeric (5–10 ppm) scale inhibitors. A 2-hour protection time with or without any detectable barite nucleation was used to define the scaling risk. To detect barite nucleation, two novel apparatuses were developed—a modified dynamic flow loop and a batch reactor. The modified dynamic flow loop has a retention time of up to 4 hours and is ideal to carry out experiments at higher than 100°C. Ba concentrations in the effluents were monitored to determine barite nucleation more precisely compared with traditional “tube blocking” technique. The new batch reactor uses our newly developed laser-detection method, a transparent pressure tube, and an oil bath. The transparent pressure tube allows laser light to pass through and can withstand 150-psi pressure at 175°C, therefore providing an efficient approach to study the precipitation kinetics of scales and to evaluate inhibition efficiency of inhibitors at HT. Constant inhibitor-concentration isopleths of diethylenetriamine pentamethylene phosphonic acid (DTPMP) for barite inhibition were constructed on the basis of our experimental data. Finally, a semiempirical model that is based on data of barite nucleation and inhibition kinetics from this study and previous work was built to predict scaling risk of barite at different physicochemical conditions. This model covers a wide range of temperature (from 4 to 200°C) and brine compositions. It also covers the effect of Ba2+–SO42− ratio in solution, common cations (e.g., Ca2+), and thermodynamic hydrate inhibitors on barite precipitation. Model precipitations were found to be consistent with field observations. The results of this study can guide the design of barite-scale treatment for HT oil-and-gas production.

Systematic Study of Barite Nucleation and Inhibition With Various Polymeric Scale Inhibitors by Novel Laser Apparatus

Summary This work reports a reliable and systematic study of barite-nucleation kinetics in the presence of scale inhibitors from 4 to 90°C and at various conditions. In this study, we designed and developed an apparatus to study the nucleation kinetics of barite-scale formation by monitoring the change of photocurrent created by a 5-mW, 635-nm red laser. The photodetector has a wide wavelength range in which sensitivity has a peak at 960 nm. A set of convex and concave lenses was used to control the beam diameter so that it can pass through more particles and increase the sensitivity. Temperature and mixing procedure were precisely controlled by an external waterbath and magnetic stirplate, respectively. The photocurrent output was constant when the laser is shining through a clear solution before scale formation. After scale occurred, laser was scattered by scale particles, which causes the decrease of photocurrent. One can expand this method to study nucleation kinetics of other scales such as carbonates, other sulfates, and sulfide scales. In addition, one can customize it to perform study under high temperature, high pressure, and anoxic conditions. With this newly developed “laser” method, we successfully measured the nucleation kinetics of barite in synthetic brine (1 M NaCl, 0.1 M CaCl2) under various combinations of reaction parameters including temperature (T), pH, saturation index (SI), and Ba2+/SO42− ratio (R). Furthermore, the inhibition efficiency of various scale inhibitors including sulfonated polycarboxylic acid, polyvinyl sulfonate, and inulin on barite precipitation was also investigated. On the basis of the experimental results, the relationship of precipitation kinetics of barite as a function of T, pH, SI, and R was established. Results of this study will be incorporated into scale-prediction software to predict the risk of scale formation and the efficiency of scale inhibitors.