Evalution of thermal desalination plants water chemistry

This paper introduces a new scale inhibitor evaluation technique that has beensuccessfully employed in screening scale inhibitor performance for offshorescale control projects and operations. For example, a sudden and unpredictedincrease in barium sulfate scaling in a seawater injected field required rapidselection of a new scale inhibitor that could inhibit both carbonate andsulfate scaling without dispersed particles. Finding the right inhibitorrequired testing of 24 chemicals, determining the minimum effectiveconcentrations at three different water chemistries to satisfy fieldrequirements. The kinetic turbidity method provided fast and efficientscreening of these inhibitors. The technique employs a spectrophotometer withtemperature control (4°C - 97°C), multi-cell capability, each of the 12 cellsequipped with magnetic stirring. Turbidity is measured at 500nm over a two hourtime period. Use of this technique enabled rapid screening of 24 chemicals in2–3 different water chemistries with effective inhibitors further tested underdynamic tube blocking conditions in 3 months. This enabled timely selection ofscale inhibitor for offshore production. This kinetic turbidity technique notonly provides information on scale inhibitor performance, but also richinformation on scale formation kinetics, inhibition mechanism andinhibitor-brine compatibility. The kinetic turbidity plots for differentinhibition mechanisms and examples of inhibitor screening test results will bepresented. This technique has become a standard method for scale inhibitor screeningproviding rapid assessment of scale inhibitor effectiveness and is used as thefirst line of testing for scale inhibitor selection in our laboratories. It isespecially useful when logistics and time constraint problems occur, which areoften found in offshore production. Introduction Scale and its prevention is a major flow assurance issue for most oilproduction at some time in the life of a producing field. Since effective scaleinhibition depends on many factors including field conditions, pressure andtemperature, water chemistry, whether the field is water flooded, changes inconditions over the life of the field, each field requires testing of scaleinhibitor effectiveness to meet the requirements for effective scale control. Two common testing methodologies are the dynamic tube blocking test (Bazin etal. 2005; NACE International Publication 31105) and the static bottle test(NACE TM0197-2010; NACE TM0374-2007). The dynamic tube blocking test measuresthe effectiveness of scale inhibitors in preventing scale build-up in acapillary tube using a flowing system. The static bottle test measures theeffectiveness of scale inhibitors in preventing general scale formation, whether in bulk phase or on the bottle surface. This is both a visualassessment and measurable by following the water chemistry of the sampletested. The most widely used test method for scale inhibitor evaluation in the industryis static bottle test. Static bottle test is a low cost, quick test to evaluateinhibitor's performance on scale formation control in bulk solution. Procedureof static bottle testing involves mixing synthetic cation and anion solutionsbased on the field's water analysis along with scale inhibitor at differentinhibitor concentrations, incubate samples at temperature for a specifiedlength of time, filter and submit the solution for ion analysis. In this test, multiple samples can be run at the same time.

For several recently developed oil fields conventional scale inhibitor chemistry has been found to be ineffective in controlling/preventing scale formation. The failure of these scale inhibitors has been due to several factors; most notably a combination of high barium and calcium ion levels with low bottomhole pH and high reservoir temperatures. BP operates one such field, the Miller reservoir. The development of a suitable scale inhibitor for Miller was considered essential to enable the field to be produced effectively without the use of more sophisticated and costly facilities, such as reverse osmosis units for seawater treatment prior to injection. The development of more effective scale inhibitors was progressed by identifying a relationship between inhibitor performance and molecular structure. From this relationship, several inhibitors were developed which showed significant improvement over commercially available products when evaluated in the laboratory. The best inhibitor, PO-85, has now been produced under licence by a major chemical manufacturer, and is ready for deployment on Miller.

Implementation of the program of import substitution considered on the example of pilot tests (PT) of reagents produced by NPF Travers LLC. The existing water chemistry of steam boilers and heat recovery steam boilers of RN-Tuapsinsky Oil Refinery LLC gas-turbine power plant is organized with the use of complex reagent Helamin BWR-150H. Considering the advantages and disadvantages of complex reagents for the organization of water chemistry, it was proposed to conduct PT of reagents AMINAT KO-4 based on a mixture of polyphosphates to prevent scale formation on heat transfer surfaces and AMINAT PK-2 based on mixtures of neutralizing amines to prevent carbon dioxide corrosion. The article presents the results of the PT, which showed that the correctional water chemistry of boilers using reagents AMINAT ensured the maintenance of the regulatory requirements of the regime maps of the equipment, as well as minimizing the processes of corrosion, scale formation and sludge formation during the entire period of work. Based on the results obtained, conclusions were drawn on the technical and economic feasibility of using these reagents.

Alkaline scale formation restriction in desalination plants by means of antiscalant additives

The Sharm El-Sheikh area is one of the most attractive touristic resorts in Egypt and in the world in general. The Sharm El-Shiekh area is located at the arid region of the South Sinai Peninsula, Egypt. Water desalination is considered the main freshwater supply for hotels and resorts. Scarcity of rainfall during the last decades, high pumping rates, disposal of reject brine water back into the aquifer, and seawater intrusion have resulted in the degradation of groundwater quality in the main aquifer. Water chemistry, stable isotopes, Seawater Mixing Index (SWMI), and factorial analyses were utilized to determine the main recharge and salinization sources as well as to estimate the mixing ratios between different end members affecting groundwater salinity in the aquifer. The groundwater of the Miocene aquifer is classified into two groups: group I represents 10 % of the total samples, has a moderately high saline groundwater, and is mostly affected by seawater intrusion. Group II represents 90 % of the total samples and has a high groundwater salinity due to the anthropological impact of the reject brine saline water deeper into the Miocene aquifer. The main groundwater recharge comes from the western watershed mountain and the elevated plateau while the seawater and reject brine are considering the main sources for groundwater salinization. The mixing ratios between groundwater recharge, seawater, and reject brine water were calculated using water chemistry and isotopes. The calculated mixing ratios of group I range between 25 and 84 % recharge groundwater to 75 and 16 % seawater, respectively, in groundwater located close to the western watershed mountain indicating further extension of seawater intrusion. However, the mixing percentages of group II range between 21 and 88 % reject brine water to 79 and 12 % seawater, respectively, in groundwater located close to the desalination plants. The outcomes and conclusion of this study highlight the importance of groundwater management to limit further groundwater deterioration of the Miocene groundwater aquifer and limit seawater intrusion along the coast.

The work addresses technical issues of waterflooding operations in offshore environments from the standpoint of fluid-fluid and rock-fluid interactions. Seawater is the preferred source of injection fluid for waterflooding in offshore reservoirs. Given the elevated CAPital EXpenditure (CAPEX), seawater treatment is generally driven by the need to mitigate injectivity loss or water compatibility issues such as the formation of hard scales. The emergence of engineered water as an enhanced-oil recovery (EOR) process has prompted the need to adjust seawater chemistry. Water chemistry modification, however, is a reservoir specific process in our view. Here, we analyze fluid-fluid as well as rock-fluid interactions for two heavy-oil carbonate reservoirs in the Gulf of Mexico to show that geochemical interactions upon adjustment of brine chemistry can lead to undesirable results depending upon lithological characteristics.Crude oils from two offshore carbonate reservoirs in the Gulf of Mexico were used in experiments. Synthetic reservoir brine was prepared based on produced water analysis. Shear and dilatational rheology were employed to estimate interfacial moduli of crude oil-brine systems, for several water chemistries. These dynamic interface properties have been found to contribute to EOR mechanisms in low-salinity waterflooding. Three different carbonate outcrop samples were used to characterize single-phase rock-fluid interactions in coreflooding experiments. Effluent samples were collected to determine cations and anions concentrations and thereby calibrate geochemical models. We contrasted the needs of seawater modification with availability of viable technologies for offshore operations, such as reverse osmosis, to envision feasible optimization of brine chemistry.Results show that geochemical interactions upon modification of equilibrium conditions in reservoirs resulting from injection of adjusted brine chemistry can lead to in situ alteration of water chemistry in a way that it impairs EOR benefits of adjusted brine chemistry injection. This is particularly severe when low-ionic strength is selected for injection in anhydrite-containing carbonate reservoirs. On the other hand, current sulfate-reducing strategies to avoid scaling in sandy reservoirs run contrary to proposed sulfate-enrichment in several oil-producing provinces. Current technologies appear to enable a broad spectrum of water chemistry modification, but implementation in offshore environments might be prohibitive for some designs.The combination of experimentally calibrated geochemical modeling with interface rheological characterization, in light of current seawater treatment technologies, offers a novel strategy to guide optimum water design for adjusted brine chemistry waterflooding operations.

The ability to safely transport wet, untreated natural gases through pipelines offshore or at other inaccessible locations is an important factor in the development of new gas fields. The internal corrosion rate of steel pipelines varies in a complex way with the gas composition, specifically CO2 , O2 , and H2 S, and condensed water chemistry. Estimating the corrosion rate of steel at inaccessible locations from the analysis of the gas and water composition from an accessible location will enable a better determination of the need for corrosion inhibitors. Quantitative understanding of the corrosion rate of steel under these conditions will be key to an accurate risk assessment of pipelines from internal corrosion. Previous work examined the effects of gas composition and slow liquid flow conditions on corrosion of steel. A parametric equation was developed that essentially reflected the deleterious effects of CO2 and O2 , and the beneficial effect of H2S on corrosion (Lyle, 1997). While this study provided important information regarding the deleterious effect of oxygen in the gas phase, the effects of condensed water composition, especially scale-forming species such as calcium and magnesium, were not examined. Furthermore, a better thermodynamic and kinetic understanding of the effects of the gas and liquid phase composition was needed. The present project, while an extension of the previous project, breaks important new ground: (i) the water chemistry typically found in pipelines is included in the tests; (ii) the scale and corrosion product formation is examined using a thermodynamic speciation software; (iii) surface analysis of the corroded samples is performed using laser Raman spectroscopy in order to confirm the thermodynamic model prediction; and (iv) electrochemical tests are conducted to understand the corrosion kinetics. A discussion of the general literature on internal corrosion is presented in the next section, followed by a summary of results from previous SwRI projects in this area. The thermodynamic approach and results are presented in Chapter 2. The experimental results are presented in Chapters 3 and 4, respectively, along with a discussion of the results in terms of thermodynamic and kinetic framework. Chapter 5 summarizes the results of this project and provides recommendations for further investigations. Details of the thermodynamic calculations, electrochemical experimental results, and analyses of the corrosion products are presented in the appendices.

An overview of the neutralizing amine based reagent AMINAT PK-2 usage for water chemistry of steam boilers for medium pressure boiler was given. Long term experiment showed that new reagent allows to decrease corrosion rate comparing with old water chemistry based on ammonia only. Two dosage schemes in different cycle places discussed. Scheme with two points on injection showed better results. Results of corrosion rates experiments and photos of tubes inner surfaces are presented. Based on fuel savings due to reducing scale formation the total annual economy for last year was 5.1 million Russian roubles.

Precipitation (crystal growth) in supersaturated solutions is governed by both kenetic and thermodynamic processes. This is an important and evolving field of research, especially for the petroleum industry. There are several types of precipitates including sulfate compounds (ie. barium sulfate) and calcium compounds (ie. calcium carbonate). The chemical makeup of the mine water has relatively large concentrations of sulfate as compared to calcium, so we may expect that sulfate type reactions. The kinetics of calcium sulfate dihydrate (CaSO4 {center_dot} 2H20, gypsum) scale formation on heat exchanger surfaces from aqueous solutions has been studied by a highly reproducible technique. It has been found that gypsum scale formation takes place directly on the surface of the heat exchanger without any bulk or spontaneous precipitation in the reaction cell. The kinetic data also indicate that the rate of scale formation is a function of surface area and the metallurgy of the heat exchanger. As we don't have detailed information about the heat exchanger, we can only infer that this will be an issue for us. Supersaturations of various compounds are affected differently by temperature, pressure and pH. Pressure has only a slight affect on the solubility, whereas temperature is a much more sensitive parameter (Figure 1). The affect of temperature is reversed for calcium carbonate and barium sulfate solubilities. As temperature increases, barium sulfate solubility concentrations increase and scaling decreases. For calcium carbonate, the scaling tendencies increase with increasing temperature. This is all relative, as the temperatures and pressures of the referenced experiments range from 122 to 356 F. Their pressures range from 200 to 4000 psi. Because the cooling water system isn't likely to see pressures above 200 psi, it's unclear if this pressure/scaling relationship will be significant or even apparent. The most common scale minerals found in the oilfield include calcium carbonates (CaCO3, mainly calcite) and alkaline-earth metal sulfates (barite BaSO4, celestite SrSO4, anhydrite CaSO4, hemihydrate CaSO4 1/2H2O, and gypsum CaSO4 2H2O or calcium sulfate). The cause of scaling can be difficult to identify in real oil and gas wells. However, pressure and temperature changes during the flow of fluids are primary reasons for the formation of carbonate scales, because the escape of CO2 and/or H2S gases out of the brine solution, as pressure is lowered, tends to elevate the pH of the brine and result in super-saturation with respect to carbonates. Concerning sulfate scales, the common cause is commingling of different sources of brines either due to breakthrough of injected incompatible waters or mixing of two different brines from different zones of the reservoir formation. A decrease in temperature tends to cause barite to precipitate, opposite of calcite. In addition, pressure drops tend to cause all scale minerals to precipitate due to the pressure dependence of the solubility product. And we can expect that there will be a pressure drop across the heat exchanger. Weather or not this will be offset by the rise in pressure remains to be seen. It's typically left to field testing to prove out. Progress has been made toward the control and treatment of the scale deposits, although most of the reaction mechanisms are still not well understood. Often the most efficient and economic treatment for scale formation is to apply threshold chemical inhibitors. Threshold scale inhibitors are like catalysts and have inhibition efficiency at very low concentrations (commonly less than a few mg/L), far below the stoichiometric concentrations of the crystal lattice ions in solution. There are many chemical classes of inhibitors and even more brands on the market. Based on the water chemistry it is anticipated that there is a high likelihood for sulfate compound precipitation and scaling. This may be dependent on the temperature and pressure, which vary throughout the system. Therefore, various types and amounts of scaling may occur at different locations. Although it has been shown that decreased pressure causes increased scaling, it is unclear if this condition will have significant affect, as all the pressures are low. Sulfate concentrations predominate, but there is still a chance for calcium carbonate buildup, especially in the heat exchanger where the temperatures are rising. Additional information is needed to conduct a thorough analysis, but it would appear that a fairly simple injection system would be sufficient to address scaling issues.

A primary objective of this study was to characterize the corrosive potential of the benthic boundary layer at a site where selected metal alloys were being exposed. Those properties of sea water and sediment likely to affect the corrosion of alloys that were measured in this study include salinity, pH, scale-forming cations, redox potential, dissolved gases, heavy metal ions, abrasive particulates, and microorganisms. The chemical properties of water from the benthic boundary layer do not appear to differ substantially from those of surface sea water. Salinity, pH and major ion content of this water appear to be representative of well-oxygenated, unpolluted oceanic water. On the basis of the properties examined, it is expected that corrosion of metals exposed in the deep sea would not differ greatly from that in surface waters having similar properties. However, the effect of pressure on corrosion rates and chemical forms of corrosion products may be an unknown factor of major importance. Increased calcite solubility at depth has been well-documented and the resulting inhibited formation of protective scale may be indicative of the effects of pressure on corrosion. The presence of sulfate-reducing bacteria in the bottom sediments at this site indicates that, if diffusion of O/submore » 2/ into the sediment was inhibited, stainless steels buried in the mud would lose passivity and corrosion rates would increase. The eventual fate of corrosion products is dependent on their properties and the properties of their environment. In benthic boundary layer sea water it might be expected that corrosion products would be released as metal oxides. (JGB)« less

In oil and gas production, corrosion (due to the presence of CO2 or/and H2S) and scale formation (CaCO3, MgCO3, etc.) are two very common phenomena having a significant impact on pipeline integrity. Although corrosion and scaling occur simultaneously in a production environment [1], they are often investigated separately in a research setting, rendering potential interaction effects difficult to evaluate. Scale formation happens because brines, which are omnipresent in hydrocarbon production systems, contain cations such as Ca2+ [2]. Consequently, if the aqueous solubility limit of CaCO3 is exceeded precipitation will occur and scaling results [3]. There is minimal, often contradictory, literature concerning the effect of Ca2+ on CO2 corrosion. This highlights the need for further systematic experimental studies in this frequently ignored area of corrosion research. A key influencing parameter in studying the effect of calcium-containing solutions on CO2 mechanisms is the saturation degree of test electrolytes with respect to CaCO3; this greatly influences the precipitation kinetics of CaCO3. Previous corrosion studies have focused mostly on the concentration of Ca2+ as the core parameter and ignored the degree of saturation. In addition, the lack of control or reporting of key experimental parameters, such as mass transfer rate and especially solution chemistry, often blurred the interpretation of the data and rendered the main findings of these studies difficult to extrapolate. The present work describes the influence of saturated solutions with respect to CaCO3 on CO2 corrosion behavior of ferritic-pearlitic UNS G10180 carbon steel. Particular efforts were made to control and report the water chemistry (pH, Fe2+, Ca2+ concentrations) and the flow characteristics of a glass cell test system. The experimental setup involved several flat, square steel specimens mounted on specially made concentric holders, all facing a central Rushton-type impeller (4.1″ ID). This setup mimicked the mass transfer rate generated by a fluid flowing at 0.5 m/s in a 0.1m ID pipe. The corrosion behavior was studied in-situ by electrochemical methods (LPR/EIS). Characterization of the surface carbonate layers was carried out by SEM/EDS and XRD. Two experiments were performed, one in CaCO3 saturated solution and one without Ca2+ ions (baseline); other than that, both tests were conducted at the same conditions (80°C, pH 6.2, pCO2 0.53 bar, 1 wt.% NaCl, and ). Fig. 1 shows the average corrosion rate versus exposure time, measured by LPR, for both experiments. The error bars indicate the maximum and minimum values at each average point. Three distinct regions were identified based on corrosion rate for both electrolytes; active corrosion, nucleation and growth of carbonate layers, and a pseudo-passivation region. Corrosion rate increased in the first region, associated with development of residual iron carbide networks. The porous structure of Fe3C provided more surface area for hydrogen evolution reaction to occur and thus increased the corrosion rate [4]. In the second region, the Fe3C network reached a thickness of 20-30 μm, for both experiments. The water chemistry within the Fe3C network was expected to be different from the bulk; high ferrous ion concentration along with high pH favored nucleation and precipitation of carbonate crystals within the porous structure of Fe3C and adjacent to the steel surface for both sets of tests. In the pseudo-passivation region, the steel potential noticeably increased, indicating formation of a protective layer on the steel surface. Although, the corrosion behavior of both electrolytes (with and without Ca2+/CaCO3) was almost identical, further surface characterization of the specimens surface revealed some differences. The corrosion products for the saturated solutions with respect to CaCO3 were a combination of Fe3C and a solid solution of FexCa1-xCO3 where 0.9<x<1, while corrosion products for the baseline test were identified as Fe3C and pure FeCO3. In conclusion, this study showed that saturated solutions with respect to CaCO3 do not have a considerable effect on the surface carbonate layers. In other words, the protectiveness of FexCa1-xCO3 is comparable to pure FeCO3 for 0.9<x<1. Further work will be dedicated to environments with higher Ca2+ contents, better mimicking field environments.

A common method of preventing scale formation on the internal surfaces of the condenser and heat ex-changers at thermal power plants with circulatory cooling systems (CCS) is correctional treatment with an addition of sulfuric acid for acidifying make-up water and reducing its alkalinity and the alkalinity of recycled water and dosing of oxyethylidenediphosphonic acid (OEDFK) for preventing scale deposit formation. The existing method of correction treatment does not provide the necessary degree of heat exchange equipment protection from scale formation. With this method of cleaning, it is impossible to completely remove deposits from the surface of the tubes to «pure» metal; the concentration of sulfates in the purge water often exceeds the permissible level. Improving the efficiency of water conditions requires developing a calculation method and creating a pilot plant for monitoring scale formation and corrosion through estimation of water chemistry directly in industrial conditions, which is the goal of this work. The circulating water corrosivity was studied on a stand that simulates the operation of circulatory cooling systems. The coil simulating water movement inside heat exchangers contained carbon steel and brass corrosion rate witness plates. A quantitative assessment of the biological contamination of the circulating water of the cooling system of the CCPP ПГУ-450 MW was carried out using total bacterial count (TBC) express tests. To estimate the probability of carbonate salt deposition in heat exchange equipment, we have proposed a method of calculating the existing values of the stabilization factor (calcium transport). The proposed method has been used to estimate the state of water chemistry of the circulatory cooling system of CHP PGU-450 MW. Calculations confirmed by the data of chemical analyzes of water and deposits have shown increased deposit mass values on the control samples (stabilization factor less than 85 %), including biological ones (the total bacterial count exceeded the permissible value by over 104 CFU / ml). The circulating water corrosivity also increased, and the corrosion rate of steel st. 20 exceeded the standard values (0,1 mm / year). The developed technique can be effectively used for analyzing the state of both the existing water conditions of circulatory cooling systems, and any other (alternative) water chemistry directly in industrial conditions of operation of a certain CCPP.

In recent years, geothermal energy use from low-temperature sandstone reservoirs has sharply increased. Nonetheless, the injection of heat-depleted geothermal fluids has not been an easy task because of well/formation damage and operational/economic issues. Sønderborg geothermal plant is a case example of heat-mining from a low-temperature reservoir. It is in the northeast of Sønderborg towards Augustenborg Fjord. The present work takes into consideration the regional and local geology of the Sønderborg area, construction of the wells, field experience and water chemistry. The main issues of the geothermal plant appear to be related to the construction of the wells and reinjection of the heat-depleted brine. Our water chemistry analysis and PHREEQC simulations indicate that geothermal brine was saturated with respect to carbonate and barite minerals. The excess of Ca2+ and SO42− ions could have led to the formation and precipitation of carbonate and sulfate scales. Moreover, the increment of iron concentration over time could suggest the ingress of oxygen and pitting corrosion due to the presence of halide ions.

Mineral scale formation is a problem across many industries and diverse applications. Each application may have specific characteristics that must be considered if a modelling system is to be reasonably accurate. The modelling of cooling water and oil field production chemistry have been studied extensively since the 1970’s and state-of-the-art physical chemistry models developed to simulate them, even under extreme conditions. Membrane systems did not begin to receive the same rigorous treatment as oil and gas production, cooling water, and geothermal power production, until the 1990’s. Much of the software used for membrane systems relies upon simple index calculations on the level of the Langelier Saturation Index, and saturation indices based upon total analytical values. This paper discusses the practical application of advanced physical chemistry techniques commonly employed in cooling water and oil field chemistry, to application specific modelling of mineral scale formation and control in membrane systems. The techniques are discussed and applied to: Predicting scale formation;Identifying the upper driving force limit for inhibitors and blends;Developing inhibitor models for minimum effective dosage;Developing models for preventing failure due to inhibitor solubility; andModeling inhibitor synergy and competitive inhibition. The methods discussed have been validated in field applications.

This manual addresses the use of a public-domain software package developed to aid engineers in the desip of water treatment systems for aquifer thermal energy storage (ATES). The software, H20{underscore}TREAT, which runs in the DOS or UNIX Environment, was developed by the Pacific Northwest Laboratory and targeted to engineers possessing limited or no experience in geochemistry. To do this, the software provides guidance on geochemical phenomena that can cause problems in ATES systems (i.e., the formation of scale in heat exchangers, clogging of wells, corrosion in piping and heat exchangers, and degradation of aquifer materials causing a reduction in permeability). Preventing such problems frequently requires the use of water treatment systems. Because individual water treatment methods vary in cost, effectiveness, environmental impact, corrosion potential, and acceptability to regulators, proper evaluation of treatment options is required to determine the feasibility of ATES systems. The software is available for DOS- and UNIX-based computers. It uses a recently revised geochemical model, MINTEQ, to calculate the saturation indices of selected carbonate, oxide, and hydroxide minerals based on water chemistry and temperature data provided by the user. The saturation index of a specific mineral defines the point at which that mineral is oversaturated and hence may precipitate at the specified temperature. Cost calculations are not performed by the software; however, treatment capacity requirements are provided. Treatments include Na and H ion exchanger, fluidized-bed heat exchanger or pellet reactors, and CO{sub 2} injection. The H2O{underscore}TREAT software also provides the user with warning of geochemical problems that must be addressed, such as Fe and Mn oxide precipitation, SiO{sub 2} precipitation at high temperatures, corrosion, and clay swelling and dispersion.