Factors Affecting Scale Formation in Sea Water Environments – An Experimental Approach

Experimental Study of Scale Formation in Sea Water Environment

The scales found in sea-water evaporators are formed of calcium sulphate, calcium carbonate, and magnesium hydroxide. Calcium sulphate scale can be avoided by using a sufficiently dilute brine concentration to maintain the sulphate in solution. The conditions are indicated under which the formation of this scale can be avoided. Calcium carbonate and magnesium hydroxide scales are shown to be due to the carbonate alkalinity in the sea water, which is limited and reasonably constant. These scales are due to the break-up of the bicarbonate ions in the sea-water as heating and boiling occur. Up to a well-defined range of operating temperatures, a scale that is predominantly of calcium carbonate is experienced. At higher temperatures, a scale predominantly of magnesium hydroxide is formed; but both types of scale may occur in the region of the change-over zone. It is shown that the break-up of the bicarbonate ions produces carbonate ions, which give rise to the calcium carbonate scale and that, with further heating and boiling, break-up of the carbonate ions occurs with the formation of hydroxyl ions, which combine with magnesium ions to form the magnesium hydroxide scale. It is shown that some of the alkalinity leaves the evaporator with the blow-down; as calcium carbonate in solution, or calcium carbonate and/or magnesium hydroxide in suspension. The amount of scale formed is found to be proportional to the amount of sea-water used, and no benefit is obtained by operating at low brine densities. It is shown that the rate of scale formation is greater for low temperatures than high temperatures, and increases with the temperature difference across the heating surface. Tests show that the use of organic dispersive compounds gives rise to a weaker scale structure, which allows some of the scale to be shed by cracking. The calcium carbonate and magnesium hydroxide scales can be completely prevented if the appropriate quantity of hydrogen ions is supplied by the injection of acids such as hydrochloric acid or sulphuric acid, or an acid salt such as sodium bisulphate. These scales can also be prevented by the injection of ferric chloride, which provides a supply of ferric ions. The ferric ions combine preferentially with the hydroxyl ions formed by the break-up of the bicarbonate and carbonate ions— thus allowing the formation of ferric hydroxide, which is very insoluble and is maintained in suspension in the brine without forming scale. Long-period tests on large commercial plants have confirmed the research tests.

Thermal desalination processes involve the heating of seawater to form water vapor which is then condensed to produce salt free water. Multiple Effect Evaporation (ME) and Multiple-Stage Flash distillation (MSF) are the two main processes used for thermal distillation. MSF distillation, currently is the dominant process. MSF distillation is run under pressure at relatively high temperatures (90-125 °C). Scale formation is one of the most critical problems affecting both processes. In the case of MSF, calcium carbonate, magnesium hydroxide and calcium sulfate are the main scale forming salts. The first two scale former salts are usually controlled by keeping neutral the pH of the system by the addition of acid. Scale inhibitors are used to prevent calcium sulfate scale. Because of economical reasons, the trend in the industry is to operate systems at as high a temperature and concentration factor as possible in order to increase purified water production at a lower cost. Safety concerns have also increased the need for acid feed elimination as a mean of controlling pH1. These practices increased the scaling tendencies in MSF processes and created the need for more effective treatment programs to control scale formation on heat exchangers. A new multicomponent inhibitor program that enable operation of MSF systems without the need of acid feed for pH control has been developed. The program prevent scale formation and allows to operate the system under typical or higher concentration factors and temperatures than normally found in MSF evaporators operating with acid feed.

In multiple-effect distillers (MEDs) with horizontal tube falling film evaporators, difficult-to-control scale is formed on the outside of the tubes, causing considerable capital, operating, and maintenance costs. Because seawater is a multicomponent electrolyte solution, scale formation is primarily caused by coprecipitation of inorganic salts, such as calcium carbonate, magnesium hydroxide, and calcium sulphate, which are insoluble at elevated temperatures. Therefore, solubility data and rate constants obtained under single-salt precipitation are not applicable. The presence of another precipitating salt in the solution affects the precipitation thermodynamics and kinetics, as well as scale structure and strength. Because the scaling process is complex, research primarily has been restricted to single-salt precipitation. A horizontal tube falling film evaporator in pilot-plant scale was used to study scale formation under conditions approximating industrial MEDs at an evaporation temperature of 75 °C, exceeding the top brine temperatures currently used in MEDs. To investigate the interactive effect of mixed salts, experiments were conducted with artificial seawater and model-solutions based on artificial seawater with varying calcium or magnesium concentrations. Scale on the outside of horizontal tubes was analyzed with scanning electron microscopy, energy-dispersive X-ray spectroscopy, wide-angle X-ray diffraction, and atomic absorption spectroscopy to obtain structural, chemical, and quantitative information.

Study on inhibitors' performance under the condition of high concentration ratio in MED system

The roles of gas bubbling, wall crystallization and particulate deposition in CaSO 4 scale formation

The scales found in sea-water evaporators are formed of calcium sulphate, calcium carbonate, and magnesium hydroxide. Calcium sulphate scale can be avoided by using a sufficiently dilute brine conc...

Scale formation and deposition in the subsurface andsurface facilitieshave been recognized as a major cause of flow assurance issues inthe oil and gas industry. Sulfate-based scales such as sulfates ofcalcium (anhydrite and gypsum) and barium (barite) are some of thecommonly encountered scales during hydrocarbon production operations.Oilfield scales are a well-known flow assurance problem, which occursmainly due to the mixing of incompatible brines. Researchers havelargely focused on the rocks’ petrophysical property modifications(permeability and porosity damage) caused by scale precipitation anddeposition. Little or no attention has been paid to their influenceon the surface charge and wettability of calcite minerals. Thus, thisstudy investigates the effect of anhydrite and barite scales’presence on the calcite mineral surface charge and their propensityto alter the wetting state of calcite minerals. This was achievedvis-à-vis zeta-potential (ζ-potential) measurement. Furthermore,two modes of the scale control (slug and continuous injections) usingethylenediaminetetraacetic acid (EDTA) were examined to determinethe optimal control strategy as well as the optimal inhibitor dosage.Results showed that the presence of anhydrite and barite scales ina calcite reservoir affects the colloidal stability of the system,thus posing a threat of precipitation, which would result in permeabilityand porosity damage. Also, the calcite mineral surface charge is affectedby the presence of calcium and barium sulfate scales; however, themagnitude of change in the surface charge via ζ-potential measurementis insignificant to cause wettability alteration by the mineral scales.Slug and continuous injections of EDTA were implemented, with theoptimal scale control strategy being the continuous injection of EDTAsolutions. The optimal dosage of EDTA for anhydrite scale controlis 5 and 1 wt % for the formation water and seawater environments,respectively. In the case of barite, in both environments, an EDTAdosage of 1 wt % suffices. Findings from this study not only furtherthe understanding of the scale effects on calcite mineral systemsbut also provide critical insights into the potential of scale formationand their mechanisms of interactions for better injection planningand the development of a scale control strategy.

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.

Scaling in multiple-effect distillers: the role of CO 2 release

Calcium sulfate occurs in three different crystalline forms: calcium sulfate dihydrate (CaSO42H2O, gypsum), calcium sulfate hemihydrate (CaSO4•½ H2O, plaster of Paris), and calcium sulfate anhydrite (CaSO4). All these forms are more soluble than calcium carbonate (CaCO3) and magnesium hydroxide [Mg(OH)2]. In cooling water and reverse osmosis-based desalination, gypsum is the most frequently encountered scale, whereas calcium sulfate hemihydrate and calcium sulfate anhydrite are the most frequently formed salts in high-temperature processes such as multistage flash distillation.

ABSTRACTPertamina/MAXUS Southeast Sumatra Petroleum, Inc. is the largest offshore oil producer in Indonesia. CaCO3 and CaSO4 scaling in and around the submersible pumps of Pertamina/MAXUS' Farida/Zelda reservoir wells led to premature pump failures and costly workovers to bring the wells back into production. Twenty-four well brines were analyzed on-site to accurately determine brine chemistries and scale samples were analyzed to determine exact composition. Well histories were studied to find correlations of procedures which led to scaling problems. Saturation Indices, developed at Rice University and presented in the paper, were applied to the problems to give insight into the causes of the intermittent, but costly scale formation. Discussions were held with a submersible pump consultant and pumps were examined to provide additional data for the analysis. Thirteen scale inhibitors were evaluated at 225 F (107 C) and 300 psia (2.07 MPa) in a 1.1% CO2 atmosphere using a flow simulator developed at Rice University to find the most effective scale inhibitor to use in the wells to mitigate scale formation.The CaSO4 scaling problem was determined to be a result of HF/HC1 acid treatments performed on the wells to increase productions rates. These acid treatments were followed by KCl seawater overflush solutions. The problem can be eliminated through the limited use of strong acid stimulation treatments and by putting a fresh water plug between the formation and the seawater or using scale inhibitor in the seawater overflush and kill fluids. Calcium from the dissolved CaCO3 in the formation due to the acid environment precipitated with sulfate ions from seawater to form the CaSO4 scale. CaCO3 scale formed due to the increased temperature, the use of rotary gas separators and the decreased pressure in and around the submersible pumps. Since production rates need to be maximized and increased temperatures and decreased pressures are necessitated by the production scheme, it has been decided to use chemical scale inhibitors in the wells. The wells are being squeezed to protect them from CaCO3 scale formation.Wells that had phosphonate residuals from previous inhibitor squeezes had longer pump runs than wells without inhibitor protection. One specialty proprietary chemical and generic aminotrimethylene phosphonic acid (ATMP) were found to be the most effective scale inhibitors in flow through testing and wert effective at 1.5 ppm. Since the specialty chemical had precipitated in the container, ATMP was recommended.

A study of the use of polyaspartic acid derivative composite for the corrosion inhibition of carbon steel in a seawater environment

Reviewed here is the kinetics of crystal growth of sparingly soluble minerals such as calcium carbonate, calcium sulfate, and barium sulfate, which frequently cause scaling problems in oil fields. For all three electrolytes, the crystal growth is surface controlled and follows a second-order rate law with an activation energy for the growth process of 10 to 20 kcal mol(-1). The growth of calcium sulfate seeded crystal above 100 degrees C demonstrates the importance of characterizing polymorphic transformation processes. Phosphonate scale inhibitors show differing modes of Phosphonate scale inhibitors show differing modes of imbibition in systems precipitating CaCO3 and CaSO4. Introduction The formation of crystals of scale-forming, sparingly soluble minerals continues to be a very serious problem for the petroleum engineer. Scaling arises from a specific set of geological, physical, and chemical conditions. Geological factors such as ground water circulation and mineral composition may mediate in scale formation as may physical factors such as pumping rate, well pressure, and the extent of fluid addition to the oil-bearing formation. However, the principal factors regulating scale formation in the oil field are chemical and such investigations can answer many of the problems. For example, scale caused by the addition problems. For example, scale caused by the addition of surface water to an oil-bearing formation can often be eliminated by chemical treatment of the injected water. A more important scaling arises from changes in subsurface mineral solubility due to variations in temperature and pressure under down-hole conditions. The difficulties are compounded by the fact that conditions frequently encountered under down-hole conditions, notably high pressure and high temperature, cannot be readily simulated in the laboratory. Sampling of an aqueous solution brought to the surface for analysis can lead to entirely misleading results owing not only to changes in temperature and pressure, but also to the fact that the solution may be actively depositing scale minerals within the well. In addition, the possible deposition of carbonate scale is dependent possible deposition of carbonate scale is dependent upon the carbon dioxide partial pressure in contact with the solution. The minerals that appear to pose the most serious problems in oilwell scaling are the sulfates of calcium and barium, and calcium carbonate. Calcium sulfate and calcium carbonate have solubility values that decrease with increasing temperature. The higher ambient temperature in the down-hole situation will therefore encourage the formation of scale deposits of these minerals. In the case of calcium sulfate the problem is complicated by the transition between the dehydrate, hemihydrate, and anhydrite phases. These calcium sulfate polymorphs may be stable or unstable under different conditions of temperature or of ionic strength. Barium sulfate presents a particularly serious problem, since it is very insoluble and cannot be dispersed once it has deposited as scale. Numerous studies have been made of the spontaneous precipitation of sparingly soluble minerals from solutions containing concentrations of the crystal lattice ions considerably in excess of the solubility values. Attempts are usually made to use controlled methods of mixing the reagent solutions containing the lattice ions, but it is extremely difficult to obtain reproducible results from such experiments. There are probably no systems that are entirely free from foreign substances or particles that can readily act as sites for the formation of nuclei of the precipitating phase. The attainment of so-called "homogeneous" phase. The attainment of so-called "homogeneous" nucleation conditions is therefore very difficult even when extreme precautions are taken to exclude impurities and foreign particles from the solutions. Experiments are frequently conducted to determine scaling thresholds in the laboratory by mixing solutions of salts containing the lattice ions and observing the appearance of the first precipitate. Such experiments are open to the same objections as those given above, however; moreover, they are frequently carried out in such a manner as to ignore important kinetic factors in the rate of precipitation. Thermodynamic interpretations of the results assume the attainment of equilibrium and involve the thermodynamic solubility products of the precipitating minerals. precipitating minerals. SPEJ P. 117

Carbon steel pipelines are employed in the transportation of wet natural gas from source to process plant. Corrosion and formation of hydrates is an important threat to the integrity of the pipeline if not properly controlled. In order to protect pipelines from hydrate formation, Monoethylene glycol (MEG) is often used. The continuous use of pH stabilizers in natural gas pipelines can lead to the formation of desirable and undesirable scale formation. If the use of pH stabilizers gives negative effects due to the formation of unwanted scale, the increase in the pH of the system is no longer effective and corrosion rates may increase. Alternatively measures may be introduced to maintain the integrity of pipelines such as the use of corrosion inhibitor. This paper investigates conditions where there is a significant formation of corrosion scale in the form of iron carbonate in wet gas systems. The continuous use of high pH at certain points of the pipeline is reconsidered with a focus on the formation of scale. The effect that lowering the pH of the solution has on the corrosion rate and existing protective corrosion product is evaluated. Synergistic and antagonistic effects of MEG with iron carbonate scale are determined with particular considerations of the use of alternative corrosion protective methods at reduced pH.