Gypsum Scaling Research Articles

Gypsum Scale Formation on Heat Exchanger Surfaces: The Influence of Natural and Synthetic Polyelectrolytes

Abstract The precipitation and deposition of calcium sulfate dihydrate (gypsum) on brass heat exchanger surfaces from aqueous solutions has been studied using 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. A variety of natural and synthetic polyelctrolytes such as fulvic acid, tannic acid, poly-(acrylic acid) and acrylic acid — based copolymers containing sulfonic group(s) have been examined for their effects on the rate of scale formation. The results indicate that the amount of gypsum scale formed on heat exchanger surface is strongly affected by polyelectrolyte architecture and concentration of polyelectrolyte. Scanning electron microscopic investigations of gypsum crystals grown in the presence of polyelectrolytes (natural and synthetic) show that structures of these crystals are highly modified.

Integrated system for recovery of CaCO 3, NaCl and MgSO 4·7H 2O from nanofiltration retentate

An integrated membrane system has been developed in order to recover dissolved salts that are present, at low concentration, in typical feed streams to desalination plants. The experimental work aimed to obtain CaCO 3, NaCl and MgSO 4·7H 2O as solid products from nanofiltration retentate. Since gypsum scale causes reduction of SO 4 2− content in the solution and drastically limits the recovery of epsomite, Ca 2+ ions have been almost quantitatively precipitated by reaction with NaHCO 3/Na 2CO 3. Sodium (bi)carbonate solutions have been produced by reactive absorption of CO 2 into sodium hydroxide solutions carried out by membrane contactors technology. The flow sheet has been completed with a membrane crystallization stage that allows the generation of supersaturation for salts crystallization.

Use of simulated evaporation to assess the potential for scale formation during reverse osmosis desalination

The tendency of solutes in input water to precipitate efficiency lowering scale deposits on the membranes of reverse osmosis (RO) desalination systems is an important factor in determining the suitability of input water for desalination. Simulated input water evaporation can be used as a technique to quantitatively assess the potential for scale formation in RO desalination systems. The technique was demonstrated by simulating the increase in solute concentrations required to form calcite, gypsum, and amorphous silica scales at 25°C and 40°C from 23 desalination input waters taken from the literature. Simulation results could be used to quantitatively assess the potential of a given input water to form scale or to compare the potential of a number of input waters to form scale during RO desalination. Simulated evaporation of input waters cannot accurately predict the conditions under which scale will form owing to the effects of potentially stable supersaturated solutions, solution velocity, and residence time inside RO systems. However, the simulated scale-forming potential of proposed input waters could be compared with the simulated scale-forming potentials and actual scale-forming properties of input waters having documented operational histories in RO systems. This may provide a technique to estimate the actual performance and suitability of proposed input waters during RO.

Gypsum Scale Formation in White Water of a Closed‐Cycled Paper Mill

AbstractThe accumulation of calcium and sulfate ions in a process stream of a closed papermaking system may cause calcium sulfate scale formation. This study presents measurements of calcium sulfate precipitation conditions and a thermodynamics‐based model for the prediction of such precipitation conditions in the papermaking white water at 50°C. The precipitates were found to have the structure of gypsum (CaSO4·2H2O). The model calculations were compared with experimental data and found to be in good agreement.

Control of Calcium Sulfate (Gypsum) Scale in Nanofiltration of Saline Agricultural Drainage Water

A methodology for calcium sulfate (gypsum) scale control in nanofiltration of saline waters is presented. The methodology involves the use of both theoretically and experimentally determined parameters. Pitzer's thermodynamic equations for electrolytes are used to determine the gypsum scaling potential of the feed water based on its ionic composition, whereas the extent of concentration polarization at the membrane surface is determined from the film model. A proportionality factor that relates the kinetic difference between the saturation predicted by the gypsum solubility model and the actual crystallization is determined using data from glassware crystallization experiments. The last step involves an experimentally developed parabolic equation relating antiscalant (polyacrylic acid) dose to the normalized concentration factors of the saline solution. These parameters are combined into a single model for predicting the required antiscalant dose to control calcium sulfate scale in nanofiltration membrane...

Calcium sulfate (gypsum) scaling in nanofiltration of agricultural drainage water

Reclamation and reuse of agricultural tile drainage water in the San Joaquin Valley, California, by membrane desalination has been given serious consideration for nearly 30 years. The agricultural drainage water has very high levels of calcium and sulfate ions, rendering it nearly saturated with gypsum in some locations in this region. The present paper focuses on the conditions of membrane surface gypsum scale formation during nanofiltration (NF) of agricultural drainage water. Experimental studies with drainage water samples and model solutions were conducted in laboratory glassware as well as with a small plate-and-frame cross-flow membrane re-circulation unit. NF membrane experiments consisted of two types: permeate disposal to measure the effect of increasing recovery on the onset of scaling, and feed water re-circulation at a fixed concentration factor to establish performance change over time. An expression relating NF product water recovery to feed water concentration factor enabled numerous membrane scale formation studies that have direct relevance to full-scale NF systems. Glassware experiments showed that magnesium ions decreased the amount of gypsum incipient nuclei because of MgSO 4 0 complexation, which reduces the availability of sulfate ions for nucleus formation. In membrane experiments, model solutions showed that bicarbonate, magnesium ions, and humic acid retarded the onset of gypsum scaling by tying up calcium ions that would have otherwise been used for formation of gypsum incipient nuclei. Both calcium carbonate and gypsum scales may result from particulate deposition rather than membrane surface (wall) crystallization, with the likelihood of particulate fouling increasing with supersaturation.

Gypsum scale control by phosphate ester

Calcium sulphate dihydrate (gypsum) scale has been prevented at temperatures ranging from 40–90°C using organic phosphate ester as a scale inhibitor. The amount of scale deposited increases as temperature and time increase. The influence of phosphate ester on scale deposition clearly shows that the dose required for inhibition is small at low temperature and increases with a rise in temperature. The relationship between the time of the test and amount of scale deposited at the same temperature and concentration of the inhibitor are discussed. Gypsum has been inhibited through threshold inhibition as well as stabilization by adsorption onto crystal growth sites of nascent crystals altering their morphology.

Gypsum Scale Formation in Continuous Neutralization Reactors

An experimental study was carried out to determine the rate and extent of scale formation of gypsum (calcium sulphate dihydrate) on stainless steel surfaces in a continuous hydrometallurgical sulphuric acid-calcium carbonate partial neutralization reactor. The purpose of the study was to determine the effects of pH, temperature, residence time, presence of metal sulphates (Fe, Al, and Ni), addition of surfactants and addition of gypsum seed on scale growth. The rate of scale formation was found to be reduced by lower temperatures, longer residence times and the presence of nickel. pH had no significant effect. The effect of these variables on the rate of scale formation was related to the degree of gypsum supersaturation. Scale reduction through the addition of sulphonated anionic surfactants was found to be effective only under certain conditions. However, gypsum seeding was found to be an effective method of scale reduction. Scale was reduced by 50% or more at a seed concentration of 10 g/LOn a effectué une étude expérimentale afin de déterminer le taux et le degré de formation d'écailles de gypse (sulfate de calcium dihydrate) sur les surfaces en acier inoxydable d'un réacteur de neutralisation partielle en continu d'acide sulfurique hydrométallurgique et de carbonate de calcium. Le but de l'étude consistait à déterminer l'effet de plusieurs variables sur la croissance des écailles, incluant le pH, la température, le temps de séjour, la présence de sulfates de métal (Fe, Al et Ni), l'addition d'agents de surface ainsi que l'addition de semences de gypse. On a trouvé que le taux de formation d'écailles était réduit par des températures plus basses, par des temps de séjour plus longs et par la présence de nickel. Le pH n'avait pas d'effet important. L'effet de ces variables sur le taux de formation d'écailles était relié au degré de sursaturation en gypse. De plus, la réduction d'écailles par addition d'agents de surface anioniques sulfonés était efficace seulement sous certaines conditions. Cependant, on a trouvé que l'ensemencement de gypse était une méthode efficace de réduction d'écailles, avec une diminution de 50% ou plus avec une concentration d'ensemencement de 10g/L.

Gypsum Scale Formation in Continuous Neutralization Reactors

An experimental study was carried out to determine the rate and extent of scale formation of gypsum (calcium sulphate dihydrate) on stainless steel surfaces in a continuous hydrometallurgical sulphuric acid-calcium carbonate partial neutralization reactor. The purpose of the study was to determine the effects of pH, temperature, residence time, presence of metal sulphates (Fe, Al, and Ni), addition of surfactants and addition of gypsum seed on scale growth. The rate of scale formation was found to be reduced by lower temperatures, longer residence times and the presence of nickel. pH had no significant effect. The effect of these variables on the rate of scale formation was related to the degree of gypsum supersaturation. Scale reduction through the addition of sulphonated anionic surfactants was found to be effective only under certain conditions. However, gypsum seeding was found to be an effective method of scale reduction. Scale was reduced by 50% or more at a seed concentration of 10 g/LOn a effectué une étude expérimentale afin de déterminer le taux et le degré de formation d'écailles de gypse (sulfate de calcium dihydrate) sur les surfaces en acier inoxydable d'un réacteur de neutralisation partielle en continu d'acide sulfurique hydrométallurgique et de carbonate de calcium. Le but de l'étude consistait à déterminer l'effet de plusieurs variables sur la croissance des écailles, incluant le pH, la température, le temps de séjour, la présence de sulfates de métal (Fe, Al et Ni), l'addition d'agents de surface ainsi que l'addition de semences de gypse. On a trouvé que le taux de formation d'écailles était réduit par des températures plus basses, par des temps de séjour plus longs et par la présence de nickel. Le pH n'avait pas d'effet important. L'effet de ces variables sur le taux de formation d'écailles était relié au degré de sursaturation en gypse. De plus, la réduction d'écailles par addition d'agents de surface anioniques sulfonés était efficace seulement sous certaines conditions. Cependant, on a trouvé que l'ensemencement de gypse était une méthode efficace de réduction d'écailles, avec une diminution de 50% ou plus avec une concentration d'ensemencement de 10g/L.

Characterization of foulants by autopsy of RO desalination membranes

A study was undertaken to identify various types of scales that were responsible for shortening the useful life span of the membrane permeators in a commercial reverse osmosis (RO) desalination plant. Compositions of the raw and treated feed water and of the reject brine were determined using the inductively coupled plasma (ICP) spectrometry and ion chromatography (IC). Various scaling index calculations showed that the feed and brine were non-scale forming with respect to CaCO 3 (calcite), SrSO 4, CaSO 4.2H 2O (gypsum), and silica (SiO 2). Two completely fouled membrane permeators, retired from stage 1 and stage 2 of a commercial plant, were subjected to membrane autopsy using scanning electron microscopy (SEM), X-ray diffractometry (XRD), optical microscopy (OM), and energy dispersive x-ray florescence (XRF). The deposits were predominantly amorphous in nature. The membrane autopsy showed that CaCO 3, SrSO 4, and CaSO 4.2H 2O (gypsum) scales did not constitute a serious problem in the plant. The advanced phosphonate+polyacrylate based scale inhibitor had itself formed Ca phosphonate sludge, but the amount was quite small. Though below saturation, silica is believed to have been precipitated due to the catalyzing effect of trivalent Al 3+ and Fe 3+ ions. Iron fouling was the major cause of reduced life span of the membranes and, to a lesser extent, calcium-alumino-silicates.

Calcium sulfate dihydrate (gypsum) scale formation on heat exchanger surfaces: The influence of scale inhibitors

The kinectics of calcium sulfate dihydrate (CaSO 4 · 2H 2O, 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. A variety of polymeric and nonpolymeric scale inhibitors such as polyacrylates (mol wt 900–250,000), acrylate-based copolymers, polyphosphates (pyro-, tripoly-, and hexametaphosphates), and phosphonates [aminotri(methylenephosphonic acid), 1-hyroxyethylidine 1,1-diphosphonic acid, and 2-phosphonobutane 1,2,4-tricarboxylic acid] have been examined for their effects on the rate of scale formation. The results indicate that the amount of gypsum scale formed on heat exchanger surface is strongly affected by changing the functional group, molecular weight, and concentration of the inhibitor. In addition, amount of gypsum scale formed suggests an optimum effectiveness with molecular of ∼ 2000 for the polyacrylates studied in the molecular weight range 900–250,000. Scanning electron microscopic investigations of the gypsum crystals grown in the presence of polyacrylates show that structures of these crystals are highly modified. A mechanism based upon surface adsorption of inhibitors on the growing gypsum crystals is discussed. The order, in terms of decreasing effectiveness on the rate of gypsum growth, of various scale inhibitors studied is polyacrylic acid (mol wt ∼ 2,000) ⪢ hexametaphosphate > phosphonates.

Computer Simulation of Rock-Water Interactions During Water Flood of the San Andres Formation, New Mexico: ABSTRACT

Rock-water reactions in reservoirs leading to scale production, porosity modification, and mineral alteration may be simulated with PC and mainframe computer models. Chemical computer simulation has been utilized to evaluate the effect of water and rock composition, pressure, temperature, porosity, and reactivity on scaling in the reservoir and well bore for a San Andres waterflood. Results demonstrate that the primary source of scale components is the injected waters, with 5 to 25% of mineralization derived from reservoir components. Rock-water reactions can account for a maximum increase in porosity of 1 to 1.5% with porosity increasing near the injector and decreasing near the producer, but with an irregular distribution. The porosity alteration is the result of anhydrite and carbonate dissolution and gypsum and calcite precipitation. The pressure gradient between injector and producer and the fluid composition are the major causitive factors in gypsum scale production, with pressure controlling spatial distribution. Evaluation of chemical and physical parameters by computer simulation demonstrates the interplay of factors that contribute to scaling and porosity modification and suggests alternative operating procedures for reservoir management.

Pilot testing of sodium thiosulfate

AbstractPilot plant tests have been conducted to evaluate sodium thiosulfate as an oxidation inhibition additive in five lime/limestone slurry flue gas desulfurization processes. It was found that the oxidation rate of absorbed sulfur dioxide (SO2) was reduced by more than 50 percent in the presence of 100 to 200 ppm of thiosulfate ion in the scrubbing slurry. Calcium sulfate dihydrate (gypsum) scaling was eliminated and the unsaturated (with respect to gypsum) operation mode was maintained by the addition of sodium thiosulfate. Other benefits of sodium thiosulfate addition observed at the pilot plant included improvement in solids dewatering properties for limestone processes and improvement in SO2 removal efficiency for magnesium‐enhanced lime/limestone processes.

Production Technology Experience in Michigan Waterfloods

Summary Waterflooding started in the Niagaran carbonate reef oil reservoirs in northern Michigan in 1978 with Shell Oil Co.'s Chester 18 waterflood. Ten waterflood projects had been installed by Spring 1983. As a result of this experience, significant production technology practices have become established. The majority of the waterflood experience has been in Shell's Gaylord Production Unit located primarily in Otsego and Crawford counties. Specifically, the projects discussed are the Chester 18, Chester 21, Frederic 10, Hayes 15, Hayes 21A, and Mid-Charlton 10 waterfloods. In general, the waterflood program can be characterized by (1) very favorable oil program can be characterized by (1) very favorable oil production response, (2) timely and definitive production response, (2) timely and definitive surveillance techniques, (3) systematic and timely well work on injectors and producers to maintain optimum reservoir withdrawal behavior, (4) innovative application of artificial lift technology, and (5) aggressive future planning to maintain and to improve oil production response. planning to maintain and to improve oil production response. This paper elaborates on these waterflood program characterizations as follows.The favorable impact that waterfloods have had on oil production is discussed.The frequency and type of surveillance techniques are described for both injectors and producers. Some of the major techniques are pressure transient analysis, inflow performance plots, produced water cut and water weight records, injection and produced fluid analysis, hydrogen sulfide monitoring, reservoir withdrawal calculations, injection profile surveys, and well-to-well radioactive tracers.As a result of the surveillance techniques, well treatments have been designed for salt, calcium carbonate scale, gypsum scale, paraffin, and bacterial wellbore impairment. Surveillance has also resulted in continuous chemical injection programs to combat corrosion, scale, salt, oil/water reverse emulsions, bacterial formation, and H, S formation. The constant calculation of reservoir withdrawals has led to alterations in the various project operating policies.Withdrawal surveillance, inflow performance monitoring, and reservoir simulation have indicated that greater ultimate recovery, maximum operating income, and maximum present value profit will be achieved in spite of increasing volumes of water with high fluid withdrawals. Recent improvements in submersible pump technology (rotary gas separator and variable speed control) have enabled high withdrawal rates to be achieved efficiently (3,000 to 4,000 B/D [477 to 636 m'/d] fluid).An aggressive program for future activity has necessitated considerable short- and tong-term planning. Items such as facility sizing, disposal zone testing, produced water handling, electric power supply for northern produced water handling, electric power supply for northern Michigan, and source water development are some of the major items that have been studied. Introduction Waterflooding was initiated in a Niagaran carbonate reef oil reservoir in northern Michigan in 1978. Ten projects throughout the reef trend had been installed by Spring 1983. As a result of this experience, effective production technology practices have become established. This paper reviews the major production technology paper reviews the major production technology surveillance techniques and highlights some of the results. The Silurian Niagaran reefs, in which there are 600 separate fields, are located along the northern rim of the Michigan basin. Fig. 1 shows the reef trend with the locations of the five major waterflood projects. The reservoir consists of dolomite and limestone rock of the Silurian Niagaran reef and the overlying A-1 carbonate. The reservoir seal is an anhydrite bed called the A-2 evaporite. A more complete description of the carbonate reef geology is offered by Huh et al. A recent discussion of the total Niagaran reef play is given by Aminian et al. The size of the Niagaran reefs under waterflood range from 50 to 560 acres [202 344 to 2 266 249 m2 ]. The smallest has only two wells, whereas the largest has 20 wells. The design and operating programs initially planned for the waterflood projects have proved planned for the waterflood projects have proved successful. The operating data from the more mature projects have enabled development of effective production projects have enabled development of effective production technology practices. The projects discussed specifically are the Chester 18, Chester 21, Frederic 10, Hayes 15, Hayes 21A, and the Mid-Charlton 10 waterfloods that are operated by Shell Oil Co. in Otsego and Crawford counties. This paper reviewsthe favorable effect waterflooding has had on oil production;the frequency and type of production surveillance techniques;the results of some of these techniques;artificial lift considerations; andfuture planning of more waterflooding in the northern Michigan reef trend. Effect of Waterflooding on Oil Production Waterflooding has substantially increased oil production in the past 3 years. JPT P. 1446

Scale Formation During Alkaline Flooding

Summary Alkaline chemicals in enhanced recovery operations are used (1) as preflush agents, (2) with polymers and surfactants, and (3) as a principal recovery agent. In these chemical flooding techniques, the precipitation reactions of multivalent hardness ions with alkalis are of particular concern. These reactions may be prevented at the injection wells through adequate preflushing and/or the use of good-quality softened water; filtration can remove any precipitates that form at the surface. In the formation, precipitates that form at the surface. In the formation, many reactions occur that alter the injected slug significantly. Those include dissolution, mixing, neutralization, and ion exchange. Such reactions may lead to beneficial fluid diversion as precipitates form and block high-flow channels. At the producing wells, however, precipitation and deposition phenomena are undesirable because scales may form that restrict production and foul well equipment. With the current higher production and foul well equipment. With the current higher concentrations of alkali being used in the field, the development of well scaling has become noticeable and difficult to control by previously accepted practices. This paper describes the progress and experience gained at the Long Beach Unit, Wilmington, CA, alkaline pilot dealing with scales formed in producing wells. These scales have been made up variously of calcium carbonate, magnesium silicate, and amorphous silica. In particular, the reservoir characteristics and chemical conditions leading to the scale formation are discussed in detail, showing what, how, and why the scale forms. For the Wilmington alkaline pilot, the cause appears to be the mixing of very hard waters from one subzone with moderately alkaline water from other subzones. This mixing and the dissolution of formation solids by the alkali have led to scale formation in the producers closest to the injectors. producers closest to the injectors. A few general scale inhibitor formulations, useful for both formation squeeze treatments and continuous sidestream annular injection, have been effective in controlling the carbonate scale under laboratory and field conditions. However, the physical environment and mechanical limitations in the field have resulted in a new deposit, consisting mainly of amorphous silica, against which the current inhibitor systems am ineffective. We suggest field procedures for dealing with such a situation. It is anticipated that the use of appropriate chemicals and methods can lead to cost-effective scale control. Introduction Them is a large body of literature on alkaline flooding and its variations. However, few authors consider associated scale phenomena at the production wells or in laboratory studies, although it is well known that alkaline chemicals react with reservoir rock and fluids to produce precipitates. Mungan mentions briefly that produce precipitates. Mungan mentions briefly that plugging and scaling were noted in some field-test plugging and scaling were noted in some field-test production wells but gives no details. Raimondi et al. production wells but gives no details. Raimondi et al. describing a sodium hydroxide pilot in the North Ward-Estes field, observed increased gypsum scale formation in producers. This reservoir has a high gypsum content. However, no treatment was discussed. The authors also noted an increase in silica content at the producers but did not detect an accompanying increase in pH value or decrease in hardness levels in the produced fluids. The alkaline slug was believed to have been completely consumed by inaction with gypsum. In a field test at the Trekhozernoye deposit in Russia, fluid-flow diversion was reported because of swelling and migrating clays and precipitation of calcium and magnesium carbonates. The produced fluids showed a decrease in Ca++ ion with subsequent increases in HCO3 - ion. In laboratory tests evaluating alkaline flooding for an Alberta reservoir, Novosad and McCaffrey reported a white precipitate in the coreflood effluents that added to the alkali consumption. They also noted that silicates are more effective at precipitation divalent metal ions. Sydansk observed the formation of new, highly hydrated alumina-silicate precipitates in alkaline com tests; these have lower silica/alumina ratios than the original formation clays. Carbonate minerals in the core dissolved first, leading to accelerated alkaline consumption. Significant amounts of silica were dissolved from the rock matrix at elevated temperatures. A number of other studies show that alkalis react strongly with the various reservoir-rock constituents. These inactions can produce very complex ionic effluents downstream in both laboratory com tests and field production wells. Ehrlich and Wygal studied the caustic consumption of a number of clays and minerals in an attempt to quantify the contribution of each to the overall consumption. More recently, this quantification has been extended by Mohnot et al. Holm and Robertson studied the effect of various preflush agents, including alkaline silicates on divalent ion exchange in surfactant flooding. JPT P. 1466

CaSO 4 scale conditions of membranes predicted by a multi-ion thermodynamic model

The increase of TDS concentration in RO process, due to the permeation and polarization effects, together with particular internal distributions of salts can create the conditions for Gypsum scaling at membrane interfacies. The analysis of such conditions is done by a Multi-ion interaction model that describes the Gypsum solubility taking into account the nature and the amount of each ion present in concentrated brines of sea water or brackish water to be treated. The model for the activity coefficients of salts is based on a theory which considers the excess Gibbs energy of the solution as a sum of three terms: a Debye-Huckel contribution; a Born term as correction factor for the change of the dielectric constant of the solvent due to the presence of ions and other indissociated species; and a short range contribution calculated according to NRTL equation. The parametrization of the model requires only parameters characteristic of the pure components and of the binary systems.

Effects of Brine Concentration and Pressure Drop on Gypsum Scaling in Oil Wells

Abstract Gypsum scale is a problem in oil wells that produce from reservoirs containing calcium sulfate. It becomes particularly troublesome in waterflood operations where large volumes of water are being produced. The solubility of gypsum or anhydrite in water increases with pressure due to a slight decrease in total volume as the salt dissolves. Upon release of pressure a supersaturated solution is obtained that deposits gypsum for a period of time. This is believed the most reasonable explanation for gypsum deposits at the bottom of producing wells. The study reveals that the amounts of scale formed at a given pressure drop and temperature depend on the amount of sodium chloride and other salts dissolved in the brine. The quantity of gypsum deposited increases with salt concentration to a maximum, then decreases until, with strong brines, no scale is formed. Introduction Secondary oil recovery from reservoirs, containing calcium sulfate often is hampered by gypsum scale. There are numerous causes of gypsum scale. Temperature changes can alter solubility and cause scale. Water incompatibility is also a common cause of gypsum deposition. If water containing calcium is mixed with another water containing sulfate, the solubility of calcium sulfate can be exceeded, resulting in the formation of gypsum scale. Another cause is water evaporation. When water evaporates the calcium sulfate concentration increases until the saturation concentration is reached; if the water continues to evaporate, the result is gypsum scale deposition. It has been suggested that the presence of large surface areas of solid calcium sulfate with relatively small volumes of water increases solubility, and thus causes calcium sulfate precipitation when the water flows into the wellbore. Gypsum scale also can be caused by pressure decreases, which cause a lowering of calcium sulfate solubility. Experiments show that there is a net loss of volume when anhydrite is dissolved in water (Appendix A). Calculations show that an increase in pressure would tend to shift the equilibrium toward an increase in anhydrite solubility (Appendix B). Experiments have confirmed this. Apparatus The experimental apparatus consisted of a 1-liter steel pressure bomb containing crushed anhydrite (mean diameter 0.5 in.). The bomb was kept in a drying oven for temperature control. The anhydrite was washed free of all fines with distilled water. The pressure was raised using a Blackhawk hand pump. Another steel bomb (0.5 liter) was placed between the pump and the bomb containing anhydrite to separate the pumping fluid (kerosene) from the water used in the experiments. This was done to prevent corrosion of the pump by water. A pressure gauge was placed between the separating reservoir and the pump. The pump and bombs were connected by 1/8-in. stainless steel tubing. After removing the water from the steel bomb following pressure release, the water was placed in 125-ml glass bottles that were covered to prevent evaporation. Small aliquots of water were removed from time to time to determine the amount of calcium sulfate remaining in solution. Procedure The bomb was filled with water, and the pressure was increased. During the first several hours after the pressure increase, the pressure decreased somewhat, and it was necessary to pump back to the desired pressure. This pressure loss was caused by the volume loss when the solid anhydrite dissolved in the water. After the first day the pressure remained constant, and it was not necessary to adjust for the remaining period at high pressure. The increased pressure was maintained for at least 5 days to permit the calcium sulfate solubility to reach equilibrium. Experiments showed that this was sufficient time for solubility maximum to be reached (Fig. 7). Anhydrite dissolves in water very fast initially, and continues to dissolve at a slowly increasing rate, reaching a maximum value in 5 to 7 days with no agitation (Fig. 7). Over 90 percent of the total anhydrite solubility is reached in 5 hours. The dissolution rate was ascertained by removing small amounts of water from the bomb and determining the amount of calcium sulfate in the water. EDTA (ethylene-diamine tetraacetic acid) titration and atomic absorption spectrophotometric procedures were used in these tests.