Application Of Scale Inhibitor Research Articles

Synthesis and Performance Evaluation of Modified Polyaspartic-Acid-Based Scale Inhibitor

This paper focuses on the selection and application of scale inhibitor by studying the problem of pipeline scaling in geothermal well development. Adding scale inhibitor can effectively reduce the treatment cost and achieve a good scale resistance effect, but the commonly used polyaspartic acid scale inhibitor has problems such as poor scale inhibition effect and large use limitations. Therefore, a new modified polyaspartic acid scale inhibitor (His-Tyr-SA-PASP) was prepared using polysuccinimide (PSI) as the raw material and histidine (His), tyrosine (Tyr), and sulfonic acid (SA) as the modification reagent. When the dosage of His-Tyr-SA-PASP was 8 mg/L, the scale inhibition rate of CaCO3 was 94.40%. In addition, the scale inhibition effect of His-Tyr-SA-PASP on CaCO3 was better than that of PASP. At the same time, under the condition of a static experiment at 75 °C, according to the ion concentration of water samples in different scale zones, this paper also identified the ratio of four composite scale inhibitors. When the dosage of compound scale inhibitor was 100 mg/L, Sodium of Polyaspartic Acid–Diethylene Triamine Penta (Methylene Phosphonic Acid)–2-Phosphonobutane-1,2,4-Tricarboxylic Acid–Amino Trimethylene Phosphonic Acid–Copolymer of Maleic and Acrylic Acid = (10:10:5:1:9), (15:10:5:2.5:2.5), (12.5:5:10:1:6.5), and (15:5:10:4:1) and the scale inhibition rate was more than 95%. Under the condition of a dynamic experiment, the optimized composite scale inhibitor still showed a scale inhibition rate of more than 90%. It provides a useful reference for the practical application of water treatment in geothermal wells and has the prospect of industrial application.

Effect of Produced Sand Particles and Fines on Scale Inhibitor: A Review

Application of scale inhibitors in oil and gas production is aimed at mitigating scale blockage during production. Many experimental, mathematical, and numerical simulation modeling works have been carried out to evaluate behavior, performance, and interaction of the scale inhibitor chemicals within porous media in relation to their efficiency in solving scale problem. However, the mechanisms underpinning scale inhibitors performance are not well published. Some research works have shown theoretically that not all scale inhibitors pumped into the formation adsorb onto the formation rock. Some of the inhibitors may adsorb on produced loose sand grains or colloidal fine sand particles which float and flow within the pore spaces along with the scale inhibitor mostly in unconsolidated reservoirs This paper provides a review of research work on the effect of produced loose sand or colloidal fine particles flow on polyphosphonates and polyphosphinopolymer scale inhibitors performances during crude production.

Enhanced scale inhibition against Ca3(PO4)2and Fe2O3in water using multi-functional fluorescently-tagged antibacterial scale inhibitors

P-Free copolymers display enhanced scale (Ca3(PO4)2and Fe2O3) inhibition, improved antibacterial performance, and reliablein situfluorescence detection of concentration.

Effectiveness of Calcium Sulfate Scale Inhibitors in Spent Hydrochloric Acid/Seawater System

Previous results have reported the precipitation of calcium sulfate during matrix acid treatments when seawater was used to prepare HCl-based acid. Precipitations of calcium sulfate causes severe damage on the permeability of carbonate reservoirs and negatively impacts the performance of acid treatments. Typically, scale inhibitors are applied in the field to prevent the formation of calcium sulfate scale, and the object of this study is to evaluate the effectiveness of different types of scale inhibitors to inhibit the formation of calcium sulfate scale during the acid stimulation process. Scale inhibition efficiency was determined in batch tests under different temperatures (77 to 210°F) and different degrees of spent acid conditions. Sulfate ions were analyzed in the samples of the batch tests to detect the precipitations of calcium sulfate. Results showed that application of scale inhibitors can successfully mitigate calcium sulfate scale formation up to 210°F. At higher temperatures, the rate of calcium sulfate precipitation increased and the effectiveness of all types of scale inhibitors decreased greatly. Most of the scale inhibitors were not effective in acidic conditions and some of the scale inhibitors even precipitated out of the solution in the presence of high concentration of calcium ions. Methylene phoshponic acid scale inhibitor was the most effective one under various experimental conditions. The findings in this study provided information for better calcium sulfate scale control under acid stimulation conditions.

The Effects of Barium Sulfate Saturation Ratio, Calcium, and Magnesium on the Inhibition Efficiency—Part I: Phosphonate Scale Inhibitors

Summary Conventional phosphonate-type scale inhibitors (SIs) are commonly applied for barite-scale prevention in oil fields. The barite forms when the injection water (IW), which is usually sulfate rich, is injected into a barium-containing formation water (FW). The inhibition efficiency (IE) of barite-scale inhibitors is affected by the barium sulfate saturation ratio (SR) of the brine mix and, additionally, by the presence of divalent cations Ca2+ and Mg2+. What is less well known is that the precise balance between these factors (SR and Ca2+/Mg2+ ratio) can vary significantly for different phosphonate species. This paper presents novel IE experimental results for phosphonate-scale inhibitors DETPMP and HMTPMP (penta-phosphonates), OMTHP (hexa-phosphonate), and HMDP (tetra-phosphonate). Minimum-inhibitor-concentration (MIC) levels for each SI are established by testing a wide range of brine IW/FW mixing ratios, which changes (i) barite SR and precipitated mass, (ii) molar ratio of Ca2+/Mg2+, and (iii) the ionic strength of the brine mix. The phosphonate SIs were categorized into two types on the basis of their MIC-vs.-percent-North Sea-seawater (NSSW) behavior. Type 1 (e.g. DETPMP and OMTHP) are affected principally by SR and are rather less sensitive to Ca2+/Mg2+ ratio although they do show some sensitivity to the latter factor. Type 2 (e.g., HMTPMP and HMDP) are severely affected by brine Ca2+/Mg2+ ratio as well as SR. To demonstrate these effects conclusively, a series of IE experiments is presented with varying [Ca2+] and [Mg2+] (which normally occurs in the field as the IW/FW ratio changes over time) and then similar experiments are repeated at a fixed Ca2+/Mg2+ molar ratio. The MIC level measured for both types of phosphonate SI always correlates very well with the barite SR at fixed Ca2+/ Mg2+ molar ratio (fixed case). In addition, we find the MICs of both types of SI are much lower in the fixed-case experiments (higher Ca2+/Mg2+ molar ratio), compared with the base case, because of the beneficial effect of higher [Ca2+]. The effects observed are important for field application of phosphonate SIs because they show how the various species are sensitive to the changing scaling problems as the %NSSW increases, in terms of SR and Ca2+/Mg2+ molar ratio. These results also give some important insights into the mechanism by which different phosphonates actually work in inhibiting barite scale.

The Comparison of Non-Aqueous and Aqueous Scale Inhibitor Treatments: Experimental and Modeling Studies

Summary This paper describes results from a series of comparative corefloods and static compatibility tests examining the differences in laboratory-test procedure, scale-inhibitor (SI) returns, and modeling approaches for nonaqueous and aqueous SI treatments. Two types of nonaqueous systems, one ethylene glycol (EG) -based and two oil-soluble products, each containing penta-phosphonate SIs, were investigated. Detailed compatibility and injectivity tests were carried out before coreflooding, and a carefully designed application/treatment process was required as a result of the hydrophobic nature of these products. To understand the SI-transport and -retention mechanisms for these nonaqueous systems, comparisons were made with the corresponding aqueous applications. These comparisions were made in terms of SI-return performance, flowback permeability, possible formation damage, and changes in the wettability conditions that might account for any post-treatment differences. In addition, approaches to mathematically modeling these corefloods were studied. This paper focuses on the application of a partitioning model in a standard reservoir simulator. An alternative two-phase mathematical model for such systems, which includes both interphase partitioning and adsorption, has been described in detail in another recent publication (Guan et al. 2004). All corefloods were performed with outcrop Clashach sandstone material rather than reservoir cores, and hence, the advantages of deploying nonaqueous treatments over the conventional aqueous treatments might not be evident. However, the experimental and modeling results help to capture the main transport and retention mechanisms of these nonaqueous systems in an understandable way. Results confirmed the existence of complex phase behavior during the corefloods with the two oil-soluble products. Examination of the core after flooding with an environmental scanning-electron microscope (ESEM) indicated decreased water wetness following the two oil-soluble SI treatments compared with the aqueous treatment. Numerical modeling results show that the behavior of this system is most consistent with the assumption that the SI in the nonaqueous system is only slightly soluble in the oil phase during the oil post-flush. Introduction In oil fields where seawater injection has been used for pressure maintenance and hydrocarbon sweep, scale formation has often been experienced in producer wells. Mineral scale may lead to significant production decline, and its removal once deposited is both difficult and expensive. The application of SI, often in a squeeze treatment into the near-wellbore formation, is regarded as a good method for preventing this problem. Downhole scale prevention generally is carried out by use of aqueous-based SIs (e.g., phosphonates, polyacrylates, and sulfonated copolymers). However, in situations in which relative permeability effects, water blocking, fluid lifting, or deep chemical penetration of the near-well formation are of major concern, aqueous SI squeeze treatments may not be desirable. Indeed, aqueous treatments may lead to impaired productivity, extended cleanup times, and process upsets during the flowback of the treatment fluids. Various researchers have developed an alternative treatment philosophy through the use of nonaqueous SIs, proposed initially in the late 1990s. Although the SI component in nonaqueous packages is usually based on a conventional phosphonate or polymeric species, their delivery systems are quite different, thus leading to transport and retention mechanisms that are also different, as reviewed in a recent publication (Guan et al. 2004). For example, (a) oil-soluble/miscible inhibitors (Guan et al. 2004; Wat et al. 1998a, 1998b, 1999a, 1999b; Jordan et al. 2000; Scott and Littlewood 2000; Jenvey et al. 2000) contain conventional SI products that have been manufactured to be inherently oil soluble before application; (b) in invert-emulsion systems (Collins et al. 2000, 2001; Lawless and Smith 1998; Jordan et al. 2006; Smith et al. 2000), the aqueous SI is deployed in a water-in-oil emulsion; (c) microencapsulated SIs (Scott and Littlewood 2000; Jenvey et al. 2000; Collins et al. 2000, 2001; Lawless and Smith 1998; Jordan et al. 2006; Smith et al. 2000; Bourne et al. 2000) involve the separation of chemical solution from the external environment by a wall or membrane, which is usually a polymer. One of the difficulties in applying nonaqueous SIs is that their detailed transport and retention mechanisms in porous media are much less well understood. This is true for each of these major types of nonaqueous products. Therefore, although several companies have performed successful field applications for their nonaqueous products, squeeze models that allow us to design such treatments in a systematic and routine manner are not yet routinely available.

The effect of temperature and pressure on oilfield scale formation

Dynamic tube blocking tests have been conducted to determine the effect of increasing temperature and pressure on barium sulphate and calcium carbonate scale formation, as part of a study considering the application of scale inhibitors in high pressure and high temperature reservoirs. As pressure was increased, the scaling tendency of the carbonate and sulphate scaling brines tested was found to decrease, as was predicted by scale prediction software. As temperature was increased, the scaling tendency of the carbonate scaling brine increased, whereas that of the high sulphate scaling brine system was found to decrease. The effect of temperature on scaling tendency was more significant than that of pressure. A low sulphate scaling brine was also tested and this failed to precipitate scale during the tests at the lowest temperature (50 °C), although at this lowest temperature, it was predicted to have the highest scaling tendency. Under these test conditions, the kinetic rate of scale precipitation was low, so the kinetic rate of precipitation became more significant relative to the thermodynamic drive for precipitation.

25 years experience in the development and application of scale inhibitors

This paper traces the development, of desalination scale inhibitors from the early polyphosphate based formulations through to the latest high temperature additives. Advances in desalination plant technology are outlined with special reference to the changing demands made on the additives. A comparison of acid and additive treatment methods is made and the various basic mechanisms of scale formation are briefly covered, together with the principal plant design factors affecting inhibitor efficiency. The long term suitability of an additive is examined with reference to the ease of plant cleaning and the maintenance of demister efficiency as well as the more obvious parameters such as the maintenance of clean heat transfer surfaces throughout the plant. A test rig permitting the laboratory evaluation of inhibitor formulations under simulated plant conditions is described. The paper concludes with an attempt to predict future trends in plant design and the type of inhibitor required for successful long term plant operation.