Summary. In this paper, we study the influence of the seed surface area, supersaturation ratio, bicarbonate ion concentration, and pH on the calcite precipitation rate. All other things being constant, the rate is a nearly precipitation rate. All other things being constant, the rate is a nearly linear function of seed surface area and supersaturation ratio. The rate also, surprisingly, depends on the concentration of bicarbonate ion, which is not a thermodynamically relevant species. There is no discernable effect of pH on the rate after the effects of pH on the supersaturation ration and bicarbonate ion concentration are accounted for. Introduction Calcite is one of the primary scale-forming minerals responsible for the fouling of oilfield production wells and equipment. Because of its importance, its rate of formation and the influences of various metal ions and other compounds on that rate have been studied extensively. Virtually all these other studies either implicitly assume or explicitly state that precipitation rate in a well-mixed system is a function only of the amount of seed and the saturation ratio (SR). The primary goal of this work is to solve a puzzle that we had observed some time ago that conflicts with the assumptions stated above: the rate of calcite scale formation appears to proceed faster at lower pH than at higher pH. This is not predicted by any published model, nor pH. This is not predicted by any published model, nor has it been reported in the literature to the best of our knowledge. Another goal is to determine, if possible, what mechanism determines the rate of calcite scale growth. These are part of the overall goal: to predict scaling severity from water chemistry and physical parameters. Theoretical treatments of the rate of crystallization start from the premise that nucleated precipitation rates depend only on surface properties and the free energy change involved in crystallization. The free energy change is proportional to the saturation index (SI), which is proportional to the saturation index (SI), which is proportional to log of SR, or SR-1 for SR near one. proportional to log of SR, or SR-1 for SR near one. The relevant surface property to be considered depends on the model considered. For diffusion-limited growth, the relevant property is simply the surface area. Crystallization rate is known to be diffusion-limited in a stagnant pool. In wells, production equipment, and our experiments, the flow is turbulent or swiftly moving and the rate is not likely to be limited by bulk diffusion. Even in turbulent flow, however, a stagnant boundary layer exists around each calcite particle. If diffusion through this layer is rate-determining (i.e., diffusion is slower than incorporation into the lattice), then the rate should be strictly proportional to the seed surface area. If the rate is diffusion-limited, it should also be proportional to the concentration or activity difference between proportional to the concentration or activity difference between the surface and the bulk solution outside the boundary layer. This follows from Fick's law. If incorporation is fast, the SR at the surface is unity; the rate will then be proportional to the bulk SR minus unity for all SR where the proportional to the bulk SR minus unity for all SR where the rate is limited by diffusion through the boundary layer. It is generally agreed that for crystalline growth to occur at low supersaturations, growth units must be incorporated into a crystal along the self-propagating surface step that results when a line defect in the bulk crystal intersects the surface. This surface step twists itself into a spiral-shaped curve during crystal growth, and this model is called the spiral growth model. The spiral growth model was originally developed to describe the crystalline growth that occurs when neutral molecules are deposited from a vapor onto a crystalline surface. Incorporation of molecules into the crystal at the step has been shown to be the rate-controlling step in that case. Such surface spirals have unequivocally been shown to exist on ionic crystals grown from solutions and can be shown to be necessary to explain the "high" growth rates observed for such crystals. Whether this incorporation step is the rate-determining step for ionic crystallization from solution is an open question. It is generally believed that this is the step in crystal growth with which threshold inhibitors interfere. The spiral growth law predicts a rate proportional to the number of growth spirals involved, with some slight modification because of spiral cooperation and interference. The number of spirals can be argued to be proportional to the initial seed mass, to the seed mass present proportional to the initial seed mass, to the seed mass present at any time, or to the seed area. The spiral growth law also predicts a rate that is proportional to the SI at high SI and proportional to the square proportional to the SI at high SI and proportional to the square of the SI at low SI. A rate that depends on the square of the SI at low SI is usually taken as proof that the rate is controlled by incorporation into the spiral. The determination of a rate law consequently gives an indication of the controlling mechanism. Experimental Procedure All experiments were run in a jacketed 400-cm3 beaker kept at 40.0 degrees C [104 degrees F] with circulating water from a thermostatted bath. The beaker was fitted with a Teflon lid scaled to the beaker with a Viton O-ring. p. 63

Ferrous sulfide deposition is a significant oilfield problem that has not been studied extensively, partly because of the difficulty in studying it under the reducing conditions found in the oilfield, partly because of a perception that its formation can not be controlled using current technology, and partly because of a perception that it is easy to remove when it does form. The difficulties in studying it may be overcome with careful work, and the perceptions are not entirely accurate. Ferrous sulfide is not a single entity; it exists in numerous solid forms. One of the determinants of the form taken by the solid is the oxidation-reduction potential of the system. This paper discusses precautions that need to be taken when conducting studies under reducing conditions. The paper presents laboratory data obtained at defined oxidation-reduction potential and pH. It shows how the deposition of ferrous sulfides may be reduced significantly using chemicals at mg/L levels. Introduction Iron sulfide is nearly as ubiquitous in the oilfield as calcium carbonate, yet it has received very little attention in the literature on scaling. There are several reasons for this.In small quantities iron sulfide can form a protective film by itself or with corrosion inhibiting compounds1,2,3. Thus, it may not always be seen as a problem.Iron sulfide often forms a softer scale than calcium carbonate. This scale may not always block tubing to the same degree that other mineral scales do. Thus, it may be seen as less of a problem than other mineral scales.Iron sulfide sometimes may be removed with dissolvers. Thus, remediation rather than control may be perceived as a more practical course of action.Inhibitors are commonly believed to be ineffective in controlling the formation of iron sulfide. Thus attempting to control it with inhibitors may be seen as futile.Iron sulfide is much more difficult to study in the laboratory than other common mineral scales. In addition to the variables of temperature, ionic strength and scaling ion concentrations that must be controlled for all mineral scales, and in addition to the pH, which must be controlled for calcium carbonate, the oxidation potential must be controlled on the strongly reducing side. This reducing environment is impossible to maintain in contact with breathable air. This difficulty in studying it may deter researchers from conducting those studies. Adherent Iron Sulfide Iron sulfide often is a problem. When too much iron sulfide is formed it no longer provides protection from corrosion. It may crack and portions of it may flake off. The remaining deposits may provide an ideal environment for under-deposit corrosion4. Adherent deposits may interfere with the operation of pumps, valves and other equipment. They may decrease the efficiency of heat exchangers and, in extreme cases, inhibit the flow of fluids through lines. In gas systems, over extended periods of time, enough pyrophoric iron sulfide may form to pose a safety hazard when the material is exposed to oxygen. Free Floating Iron Sulfide Free-floating precipitates of iron sulfide create additional problems.The solids content of water meant for re-injection may be increased.Iron sulfide may form sludges of such volume that they significantly decrease the volume of holding tanks and separators.Iron sulfide particles may acceleration corrosion5.Oil-wet iron sulfide particles at the oil-water interface often stabilize emulsions and interfere with the separation process.

Five structurally different scale inhibitors were studied using a kinetic adsorption-desorption technique. Adsorption was fast. All inhibitors adsorbed to a similar degree. Desorption was slow. There were large differences in the degree to which different inhibitors desorbed. The kinetic desorption characteristics are more important in picking an appropriate squeeze chemical than are the adsorption characteristics. The study realistically modeled the flow rate, contact time and brine composition that might be found in an oilfield reservoir. Adsorption was measured on limestone at 40 degrees C and sand at 40 degrees c and 80 degrees C. The inhibitors were diethylenetriamine pentamethylenephosphonic acid, hydroxyethylidene pentamethylenephosphonic acid, hydroxyethylidene diphosphonic acid, a triethanolamine phosphate ester, a polyacrylic acid, and a polymeric phosphonate inhibitor. polyacrylic acid, and a polymeric phosphonate inhibitor Background The advantages of treating oil wells by the squeeze technique have been known for at least thirty years. Wells can be protected for months using this technique. The cost of the chemical is virtually the only capital cost. Treatment is automatic and continuous after the squeeze. It is the only method which protects the formation from scale damage. The succes of a squeeze is judged by its effective lifetime. The squeeze is effective as long as the inhibitor returns at a high enough concentration to inhibit scale formation. The return of the squeeze chemical is monitored by chemical means. In order to maintain the return of a high enough concentration of inhibitor, two things must happen:the inhibitor must be held in the formation;it must be slowly released into the produced fluid. Mechanisms Scale inhibitor may be held in the formation and subsequently released in one of three different ways. First, the inhibitor may be physically entrapped in the formation. This can happen in many different ways. Laboratory tests can not generally simulate these conditions. It is generally felt that this is not an effective mechanism. Second, the inhibitor may be precipitated in the formation. The conditions that influence precipitation and subsequent dissolution can be studied in the laboratory. Operators and reservoir engineers have, until recently, avoided conditions that purposely precipitate solids in the formation. They fear the danger precipitate solids in the formation. They fear the danger of damaging the reservoir. There are numerous recent papers and patents on precipitation squeezes. papers and patents on precipitation squeezes. Finally, the inhibitor may be adsorbed onto the formation solids It may be then desorbed into the produced fluids. The adsorption-desorption mechanism is produced fluids. The adsorption-desorption mechanism is attractive because it promises a slow even release of inhibitor with minimal formation damage. The adsorption of inhibitors on solids has been studied extensively. This paper is another step toward our understanding of this phenomenon as it applies to oil wells. It varies from much other work in that it uses kinetic tests. The flow rate, contact time and brine compositions are based on oil field conditions. Inhibitors Five different types of effective scale inhibitors were studied. These are:an aminomethylene phosphonate, diethylenetriamine pentamethylene phosphonate, diethylenetriamine pentamethylene phosphonic acid (DETP 5);an alkyl phosphonate, phosphonic acid (DETP 5);an alkyl phosphonate, hydroxyethylidene diphosphonic acid (HEDP);a phosphate ester, triethanolamine phosphate ester phosphate ester, triethanolamine phosphate ester (TEAPE);a tagged polyacrylic acid (PAA); anda proprietary polymeric phosphonate inhibitor (PPI). proprietary polymeric phosphonate inhibitor (PPI). P. 267

A large independent operator in Mobile Bay, Gulf of Mexico was experiencing a buildup of common and exotic scales where the produced waters are commingled.The scale species encountered included barium sulfate, zinc sulfide, and lead sulfide.Traditionally, scale inhibitor chemistries have not been used in the past to inhibit these exotic sulfide scales in this region.This is due to some amount of belief within the industry that conventional inhibitors alone could not inhibit these scale species. Prior to the application of the scale inhibitor in the field, the platform's overboard water line required cleanout every two months due to scale buildup.Not a single cleanout has been necessary since a polymeric scale inhibitor has been applied downhole via continuous capillary injection for over one year. This paper presents the results of laboratory tests which were used to demonstrate how a polymeric scale inhibitor was identified and approved for inhibition of lead sulfide and iron sulfide, as well as the more common scales.The sulfide scale tests performed in an anaerobic dynamic tube-blocking test unit showed this inhibitor chemistry to be as effective as combined scale inhibitor/dispersant products. The paper then presents the field treatment results, which shows good agreement with the lab test results. Introduction Commingled brines present problems in the surface and subsurface due to ionic species forming insoluble mineral scale species.Barium sulfate (BaSO4) and calcium carbonate (CaCO[3]) are two of the most common mineral scales encountered in the oilfield and could be considered well-understood.However, zinc sulfide (ZnS) and lead sulfide (PbS) are less common, and require a slightly different approach to treatment.It has been suggested in the past that a special type of "novel" scale inhibitor is best for inhibiting zinc sulfide and lead sulfide scales[1].Additionally, there are a handful of commercial inhibitors which are sold as specialized sulfide scale inhibitors.The goal of this work was to compare the efficacy of one of these specialized sulfide scale inhibitors versus a proprietary product chemistry to determine the relative performance under the conditions of this Mobile Bay field. Whereas most ZnS/PbS scale inhibitor evaluations have relied on static bottle tests or field test data to determine[1,2,3,4], the tests described in this paper were performed using an anaerobic dynamic tube-blocking apparatus.There are distinct advantages to be gained with the ability to compare product efficacies before progressing to a field trial stage.The anaerobic tube-blocking tests more accurately simulate the dynamic environment where the scale inhibitor products would be used than static bottle tests.The differential pressure transducer detects very minor increases in differential pressure (DP), which indicates when scale has deposited in the test apparatus. This allows nucleation inhibition properties and dispersant properties of the scale inhibitor products to be more closely evaluated than in static bottle tests. Scale Inhibitor Products The main focus of this study was to compare the performance of a commercial sulfide scale inhibitor against a proprietary polymeric scale inhibitor.Product A is a commercially-available sulfide scale inhibitor.Products B through E were polymeric scale inhibitor products provided by chemical suppliers, who indicated the chemistries might be effective as zinc sulfide and lead sulfide inhibitors.Product F is a blend of polymers.Product G is a proprietary polymeric scale inhibitor which was readily available commercially.Table 1 provides a quick reference to the generic chemistry of each product.

A novel technique has been developed to detect the onset and increase of calcium carbonate scale deposition from oilfield production fluids. This method uses an attenuated total reflectance (ATR) probe, called the scale sensor, to detect scale formation in situ. Because this method is based on existing technology and requires little supporting equipment, a simple, cost-effective monitoring device could be placed in many locations within a production system. This method could provide a system-wide, in-situ, real-time response to calcium carbonate scale formation at its earliest stages.As a first step toward evaluating the effectiveness of this new technology, the scale sensor was field tested at a west Texas oil field. The scale sensor was observed to detect the deposition of calcium carbonate under static and flowing conditions in actual produced fluids. In the static tests, crude oil, suspended solids, and other endogenous materials did not affect the scale sensor's response. Under flowing conditions, like those found in the production flowlines at this west Texas oil field, scale sensor response was observed to correlate to the chemical injection rate of both the scale inhibitor and the dispersant. On the basis of the results from the scale sensor, the scale inhibitor's injection point will soon be moved to the wellhead.