Es wird über die Darstellung, die Eigenschaften und die röntgenographische Untersuchung von Cu2BaSnS4 (A) und Ag2BaSnS4 (B) berichtet. (A) kristallisiert trigonal, — Raumgruppe C 32–P31 mit a = 6,367 und c = 15,833 Å — und ist mit Cu2SrSnS4 [1] isotyp. (B) hat eine orthorhombische Elementarzelle: a = 7,127, b = 8,117 und c = 6,854 Å. Die röntgenographische Systemuntersuchung an Cu2−xAgxBaSnS4 ( o ≤ x ≤ 2) ergibt die Phasenbreite: ( 0 ≤ x ≤ 0,65) für (A) und für (B) (1,7 < < x ≤ 2).

Summary A newly developed model to predict chemical compatibilities in waterflood operations is described. The model calculates the coprecipitation of BaSO4, SrSO4, and CaSO4 at various locations in field operations as mixtures of injection and reservoir waters flow through injection wells, reservoir, and production wells into surface facilities. As its data base, the model uses comprehensive data of actually measured solubilities in fairly complex oilfield and geothermal brines at various temperatures and at saturation or atmospheric pressure. The solubilities at high pressures are calculated using thermodynamic parameters. The application of the model is illustrated by examples involving two reservoir and two injection waters. Introduction Two of the more difficult problems in designing a proper waterflood operation are (1) the predetermination of chemical incompatibilities of waters used in the flood and (2) the forecast of these incompatibility effects on future field operations. This forecast should cover the type, extent, and location of all future damages resulting from chemical incompatibility problems.No damage of any kind would occur if all reservoir materials were chemically compatible with the injected water. However, hardly any source water available in large enough quantities is fully compatible with all materials in the reservoir to be flooded.The water native to the reservoir to be flooded is in chemical equilibrium with the rock, hydrocarbons, and any other materials present in the reservoir (e.g., CO2, N2, H2S, etc). In contrast, the water considered for injection is in equilibrium with its own environment, which is normally quite different from that in the reservoir to be flooded. Any injection automatically leads to a readjustment of most chemical parameters as soon as the injection water enters the reservoir. The newly injected water must re-establish its own and new thermodynamic equilibrium with respect to all solids and fluids present in the reservoir to be flooded.In conventional reservoir engineering and waterflood design, the fluids and rock phases are considered chemically inert. That is, these liquid, gaseous, and solid phases have physical properties that can have large effects on the flow properties but are not considered to participate actively in any chemical reaction. In reality, this is not true. Any injected water having an origin different from the reservoir to be flooded will interact chemically with the fluids and solids in the flooded reservoir. These interactions, of course, will depend on the chemical compositions of all participants in these interactions (liquid, gaseous, and solid phases), the degree of mixing, the flow paths, and the temperatures and pressures at various locations within the flooded reservoir.To complicate the situation further, the reservoir water (i.e., the produced water) may be produced at thermodynamic conditions again different from those within the reservoir. For example, dissolved CO2 and H2S may break out of solution when the water is produced together with the hydrocarbons. This loss of reactive gases will change the composition and pH of the water, thus generating a possible compatibility problem when the produced water is reinjected. This means compatibility problems can occur, at least theoretically, even during reinjection of produced formation water originating in the reservoir to be flooded.Ignoring the chemical reactions between injected waters and reservoir materials can lead to the disasters often experienced in the field. The formation of scale in producing wells is the most obvious result of the frequently encountered compatibility problems. In this paper, we describe some preflood considerations necessary for proper flood design. JPT P. 273^

This paper is an analysis of the present knowledge of the formation, removal, and prevention of scale. This examination of the state of the art is presented to indicate the limits of current knowledge of oilfield-scale problems and to instigate additional research into these problems. problems. Introduction This paper** deals with three distinctly different scalecontrol problems in oil and gas fields: prediction, removal, and inhibition. An attempt is made to analyze the state of the art and to show the narrow limits of our present knowledge. This attempt is undertaken to present knowledge. This attempt is undertaken to indicate these limits to operating people and to stimulate additional research. All the known prediction methods have many shortcomings. Hardly any predict the actual amount of scale formed under a given set of conditions. Instead, they determine scaling tendencies. We can say that the scaling tendency of barium sulfate (BaSO4) is the easiest to predict and calcium sulfate (CaSO4) is much harder to predict and calcium sulfate (CaSO4) is much harder to predict. Presently, we do not have a workable method for predict. Presently, we do not have a workable method for predicting calcium carbonate (CaCO3) scaling. predicting calcium carbonate (CaCO3) scaling. The removal of each type of scale is technically possible, though perhaps not very practical. CaCO3 scale is possible, though perhaps not very practical. CaCO3 scale is the easiest to remove. CaSO or gypsum, is much harder to attack, and BaSO4 is by far the hardest to handle. Scale inhibition is an art and is successful only in less seven: cases of scaling. We do not know of scale inhibitions that are very effective when the temperature is much higher than 350 deg. F, or when large amounts of scale per barrel of produced water are formed. The application of the inhibitors may also cause problems in the field. Some inhibitors may cause more problems than they solve: the formation of pseudoscales and extreme emulsion problems may be observed under certain conditions. problems may be observed under certain conditions. How Much of a Problem Is Scale? Anyone who is vaguely familiar with oilfield operations has heard about the scale problem. However. there seems to be confusion about the extent of the formation and wellbore damage caused by scale in oil fields. To some, scale is not much of a problem because one seldom has a chance to see or physically examine actual samples of these deposits. Many scale deposits are, of course. located outside the well within the oil-bearing formation, where they are invisible. On the other hand, despite these analytical difficulties, some people think that scale is one of the major enemies in our daily oil- and gas-field operations. I belong to the latter group, and I sincerely believe that there are few wells that do not suffer flow restrictions from scale deposits within the drainage radius inside the formation. within the wellbore, or in the surface equipment. If we try to estimate the loss of revenue caused by flow restrictions due to scale, we come up with astronomical figures. I have reason to believe that oil- and gas-field scale costs on the order of $ 1 billion/year in the U.S. alone. This sum should be considered a minimum. I also believe that the scale problem is increasing. As our oil and gas reserves are depleted, we must produce these hydrocarbons under increasingly severe production conditions. More water production will favor many of the scale-forming conditions. In addition, we "pull" harder on our wells as less oil is being produced, thus favoring again all the scaling conditions. This means that the revenue losses resulting from plugging by scale will consume an increasing portion of our income as we deplete our reservoirs. P. 1402

There are a number of gaps in our knowledge of the principles and mechanisms involved in the squeezing process. Among the things learned through a series of tests was that adsorption isotherms, contrary to common theory, are not very important to the process. And some factors that have been largely ignored flow velocity, for example are very important indeed. Introduction The squeeze technique as a means of depositing chemicals in an oil-, gas-, or water-bearing formation finds extensive use in the petroleum industry. This trend was started after the first publications of Kerver et al. on squeezes utilizing publications of Kerver et al. on squeezes utilizing the adsorption-desorption characteristics of corrosion inhibitors. Later, Smith et al. and Kerver and Heilhecker applied the same ideas to the deposition of scale inhibitors in the rock matrix around the wellbore of a producing well. Here, again, the adsorption-desorption characteristics of chemicals provided the basis for the technique. Recently, a different type of squeeze technique has been suggested by Miles. In this "precipitation" method. a dissolved chemical is first injected into the matrix and precipitated some distance from the wellbore. The precipitate is then partially redissolved by the oilfield brine at a very low but still effective concentration and transported back to the wellbore. In a previous paper, we described our tests on the compatibility of inhibitors with constituents of common oilfield brines. From these earlier data, and from the results given here, we conclude that there is no clear-cut line between these two basic types of squeeze methods. Both mechanisms can occur concurrently, depending on the chemical nature of the inhibitor and on formation parameters. However, the first mechanism (deposition based solely on adsorption-desorption characteristics) is to be preferred because it completely avoids formation damage that occurs when pores are plugged with secondary deposits. A third mechanism of inhibitor squeeze has been proposed by Tinsley et al. The inhibitor solution proposed by Tinsley et al. The inhibitor solution enters small fractures and vugs during squeezing and later slowly bleeds back into the stream of produced water. This mechanism should not play any important role in formations consisting of a sand matrix where no fractures exist. Basic Concepts of the Study We think the literature shows a lack of information regarding the following:The basic mechanisms and principles involvedin the squeeze technique.The design and limitations of squeeze jobs asa function of formation parameters (rockmaterial, formation temperature, flow rates, etc.)and the chemical nature of the squeezedcompound.Methods of evaluating squeeze tests in thelaboratory and in the field. We also believe that inadequate tools and methods are often used to conduct and evaluate actual squeezes. The "results" of these squeezes cause considerable confusion in some instances and may lead to misconceptions about the method and its value. To develop some reliable information about the squeeze method, we conducted a series of laboratory and field tests. JPT P. 339

A rating of inhibitors in the order of their effectiveness is a relative matter and depends upon test conditions. The most important conditions are the degree of supersaturation and the temperature; the higher the supersaturation and the higher the temperature the less effective a scale inhibitor becomes. Scale Inhibition Is Still an Art Scale inhibition is still closer to being an art than a science. The literature deals only to a very small extent with the problems of scale inhibition. Most of the published data do not consider the basic facts of crystallization and inhibition. such as reaction mechanisms and kinetics. Because these fundamental considerations are often neglected, there are many recorded failures of scale treating procedures in oil and gas fields. This neglect of fundamentals and lack of data is surprising because the formation of scale is a rather costly problem for some industries, above all the petroleum industry. We lose many millions of dollars petroleum industry. We lose many millions of dollars in revenue every year because scale creates flow restrictions in our fields. Accurate evaluation of scale inhibitors is the first and most important step toward effective scale control. How Are Scale Inhibitors Presently Tested? Presently Tested? Test Machines Several investigators have been concerned with the development of test machines designed to simulate the conditions of scale deposition in the field. The degree of scale buildup in these test devices is used to screen and rank commercial products and experimental chemicals. Scale Coupons The use of scale coupons in the field is a test somewhat related to the use of test machines in the laboratory. Steel coupons are inserted in flow lines, and the amount of scale they accumulate is used to evaluate an inhibitor that has been injected into the system upstream of the coupon. Precipitation Test Precipitation Test In the "chelation test," which should be called the precipitation test, two chemically incompatible precipitation test, two chemically incompatible solutions are combined. The precipitation of scale-forming solids - for example, calcium carbonate (CaCO ), calcium sulfate (CaSO,) or barium sulfate (BaSO ) is measured in the presence of an inhibitor of varying concentrations by means of chemical analyses. The amounts of precipitate obtained are then compared with the amount of precipitate formed by mixing solutions containing no scale inhibitor. The more solids that are kept in solution by a given amount of inhibitor. or the less inhibitor that is needed to keep a given amount of solids in solution, the more effective and desirable the inhibitor is thought to be. This test is widely used for laboratory evaluation of scale inhibitors. The test is very quick and convenient to run, gives fast results, does not require costly equipment, and can be run by relatively untrained personnel. Unfortunately, the reproducibility of the result is sometimes very poor, and data reported by different testers is often contradictory. P. 997