25 years experience in the development and application of scale inhibitors

Problems related to inorganic scale precipitation are common in oil fields across Russia. The predominantly calcium carbonate scale rapidly precipitates from the produced water and causes reduction in reservoir permeability, restricts fluid flow in tubing and perforation, fails electric submersible and rod pumps, and plugs surface equipment. Local industry offers a number of inhibitors to prevent scale deposition. Although regular and planned injection of inhibitors into producing and injector wells is the most common method of scale precipitation prevention, no successful attempt to enhance scale prevention in conjunction with a stimulation treatment has been documented. This paper describes the first application of a combined scale inhibitor and hydraulic fracturing treatment in Western Siberia. It allowed the operator to place significant amount of scale inhibitor within the propped fracture and into the adjacent formation. The case history delineates the detailed sampling and pretreatment analysis of several oil fields with high-water-cut wells. In some of the fields, as many as 26% of the production wells experience scale-related problems. Up to 33% of electrical submersible pumps (ESP) failures are related to inorganic scales. Further, the candidate selection process provided ground for detailed lab testing to optimize the inhibitor type and volumes required for the first scale-inhibited hydraulic fracturing application in the Novogodnee field. The pilot project wells that were hydraulically fractured with the addition of scale inhibitor yielded a threefold increase in productivity and similar initial fluid production rates. The scale-inhibited wells did though provide sustained rates over a 3-month monitoring period compared to rapid decline in production on the non-inhibited wells. At the same time, the wells treated with scale inhibitor have provided not only sustained production but also a fourfold reduction in operating cost, confirming the success of the pilot project.

Geothermal energy refers to the heat stored in the subsurface that can be extracted by producing the hot fluids (water and/or steam) in contact with the hot formation. A major issue that may restrict the extraction of geothermal energy is precipitation of mineral scales which can occur within the reservoir, inside the wellbore, or surface facilities. The objective of this paper is to find the most efficient scale treatment strategy to prevent mineral scaling. Continuous injection of chemical scale inhibitor (SI) downhole in the production well, is the most common method to prevent mineral scale in geothermal plants. This method although effective does not protect the near-wellbore area, where the highest pressure drop is expected. To address this issue, two methods will be studied, bullheading the production well with SI, commonly known as squeeze treatment, and injecting SI in the injection well. Optimum designs for both methods were identified considering different levels of SI adsorption, and also permeability variation in fractured and non-fractured formations. As expected, the volume of SI required in continuous injection in producer was lower than the other two methods. However, in cases where the highest risk of precipitation is in the near-wellbore area or it is below the continuous injection point, it is necessary to apply one of the suggested methods. While the squeeze treatment protects only the formation around the producer well, treatments deployed in injector wells will protect the whole system and this extra protection may offset the extra volume of chemical necessary. The application of SI in injector well was studied in both continuous and batch mode with different injection frequencies. It was shown in continuous injection that even though less SI volume is used, the SI breakthrough time in producer can be so long that a series of squeeze treatments might be required to protect the well. The simulation results showed that in high adsorption formations, squeeze treatment is more efficient than deploying SI in the injector well. However, in cases of low adsorption and fractured reservoirs, the scenario commonly found in geothermal plants, SI injection at the injector is more optimal. Two different scale treatment methodologies were studied in geothermal wells, including squeeze treatment in producer and SI injection in the injector and the results were compared with the continuous SI injection in producer, which is the most current treatment in geothermal wells. It was illustrated in fractured geothermal reservoirs with relatively low levels of adsorption, that SI injection in the injector is the most optimum treatment that can effectively protect the whole plant from scaling.

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.

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.

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.

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.

Mineral scale deposition is a well-known problem for the petroleum industry. The application of scale inhibitors can often prevent such deposits forming, but assessment of the concentrations of these needed for control has relied on indirect methods for assessing brine stability. Such methods use laboratory tests and measurement of scale inhibitor residuals. Recently a new technique for direct measurement of the stability of oilfield brines has been developed. This technique uses TSMR (Thickness Shear Mode Resonator) technology. Deposition on the probe alters resonant frequency, measured in real-time. This paper describes field applications of the equipment to a range of scaling environments. The Middle East application allowed successful categorization of wells with into those with likely scale problems and those unlikely to see such deposits. The onshore USA trial showed that the equipment could give an indication of potential calcium carbonate scale, besides barium sulfate. For the North Sea application, where a severe barium sulfate potential existed, on-site optimization of required scale inhibitor dosage was achieved for particular wells and combined wellstreams. In this case evidence was also provided for situations where the current scale inhibitor was incapable of completely inhibiting barium sulfate deposition.

Synthesis and evaluation of scale inhibitor with high-temperature resistance and low corrosion capability for geothermal exploitation

Lead sulphide (PbS) is one of ‘exotic’ scales deposited in the oil and gas industry. The inhibition of lead sulfide scale deposition is notoriously difficult compared to calcium carbonate and barium sulphate. In addition, it is extremely difficult to test lead sulfide formation and inhibition in laboratory with the conventional static jar and dynamic loop tests and very little is still understood about its mechanism of formation and inhibition.In this paper, a novel stress test method has been developed and applied to test the performance and understand mechanisms of lead sulphide inhibition. Compared with the traditional static jar and dynamic loop tests, this test method shows good reproducibility and provides a quick and effective way to evaluate the performance of lead sulphide scale inhibitors.Typical commercial scale inhibitors, including six phosphonate based scale inhibitors, PPCA, polymaleic acid, polyacrylic acid, polyaspartate, PVS and patented environmentally friendly polyacrylic copolymers have been tested based on this newly developed method. The performance of scale inhibitors on PbS inhibition can be classified as three types:Type 1: Dispersion inhibitors. These scale inhibitors showed a dispersion effect on PbS formation. The turbidity in stress curve in the presence of these inhibitors is slightly higher than that in the absence of scale inhibitors.Type 2: Nucleation/growth dominated scale inhibitors. These scale inhibitors inhibit nucleation and growth of PbS formation, where the test can be stressed further in the presence of these inhibitors.Type 3: Scale inhibitors with poor performance on PbS inhibition. These inhibitors showed less PbS inhibition performance. The turbidity in stress curve did not change obviously in the presence of these scale inhibitors.This paper will give the comprehensive study of lead sulfide formation and inhibition, which includes development of the test method and scale inhibitors for lead sulphide inhibition.

The study presents a comprehensive assessment of the effectiveness of measures aimed at preventing complications during the operation of wells at the Kalamkas oil field. The main directions of chemicalization of oil production processes are considered: thermal flushing with hot water and surfactant “Rauan-100,” acid treatments (HCl-based stimulation), near-wellbore treatment of injection wells with the biocide “Rancid-7004,” as well as the application of scale inhibitors “Randim-4021” and corrosion inhibitors “Rankor-1101.” The analysis showed that thermal flushing restores well productivity for a short period, acid treatments increase the injectivity index of injection wells by 1.4–1.6 times, and biocidal treatments reduce hydrogen sulfide content in the produced fluid on average by a factor of 3. The use of scale and corrosion inhibitors proved effective, extending the service life of equipment. Based on the results of the study, recommendations were developed for further application and optimization of chemical well protection technologies.

Prevention of inorganic scale damage in the formation around production wells is usually achieved by batch squeezing the productions wells at risk. However, in Western Siberia protection of production wells is sometimes achieved by application of scale inhibitors in the supporting water injection wells. This technique relies on the effective displacement of the inhibitor across the reservoir from injector to producer. This is not generally considered a viable scale management option due to the extent of chemical retardation that is a necessary result of inhibitor retention on the rock matrix. However, for short inter-well distances, such as may occur in onshore developments, and where fracture conductivity is high enough that inhibitor contact with the matrix rock is minimal, then this technique can provide adequate protection against scale induced formation damage in production wells. This paper explores the range of reservoir scenarios under which this technique may be applicable, considering inter-well distances, the extent of fracture vs matrix flow, and the potential range of inhibitor retention on various rock substrates that may be encountered in fractured reservoirs. The approach is to use numerical modelling techniques to investigate the range of conditions under which this scale management approach may be applicable. This data may then be used identify when scale control may be adequately achieved using this technique, thereby reducing the need to shut in production wells for treatments, and when this approach would not provide adequate protection in actual field systems. Comparison is made of the potential for performing batch treatments in the injections wells, compared to continuous injection of scale inhibitor in these wells.

Mineral scales, in particular calcite (CaCO3) and siderite (FeCO3) have been associated with formation damage in oil fields in Colombia. Scale deposition has been observed within the production flowline as well as in the formation. For many years, this scale problem has been addressed through the use of traditional acid treatments. However, this approach caused additional problems such as re-precipitation due to spent acid, clay swelling, and corrosion, giving rise to rapid losses in production, fine migration, and asset integrity concerns. With this in mind, a process to identify the Best in Class non-acid scale dissolver was developed. Through this process, the service company developed a new alternative based on a material with neutral pH, high dissolution capacity, and no reprecipitation. After thorough laboratory evaluation and testing, the product was successfully applied in the field. The first six applications allowed an increase in crude production of approximately 300,000 bbl. This paper details the methodology developed for evaluation and selection of the Best in Class scale dissolver used in this application, as well as the development and implementation of the strategy that allowed the successful field application of the selected material. The practical improvements achieved through this approach and how the approach can be used to develop effective troubleshooting and improvement processes will be discussed. Introduction The formation of mineral scale within the near wellbore area, production tubing, and topside process equipment presents a challenge to the oil and gas industry. The precipitation of mineral scale is a common cause of formation damage during the production of hydrocarbons and can cause significant production decline (Cowan et al., 1976). Carbonate scales (calcite, CaCO3, and siderite, FeCO3) can be formed due to pressure or temperature changes. Sulfate scales, on the other hand, are typically formed due to the mixing of incompatible waters. Scale problems are normally managed by the application of scale inhibitors. There are, however, some instances where scale inhibition alone is not sufficient to prevent production decline due to scale deposition. In these cases, scale removal using scale dissolvers may be required (Clemmit et al., 1985). Scale dissolvers are typically aqueous solutions of either acids/chelants for carbonate scale or alkaline chelating agents for sulfate scales (Fredd et al., 1998; Frenier, 2001; Benson et al., 1997; Weintritt et al., 1967; Schutte, 1987; Clemmit et al., 1985; Jordan et al., 2006) also, carbonate scale can be removed by using corrosion-inhibited hydrochloric acid (Bakken et al., 1996; Ramstad, 1997; Benson et al., 1997; Rhudy, 1993). This paper will focus on the chemical removal of calcite and siderite scale associated with formation damage in oil fields in Colombia and the process used to develop a scale control strategy that includes the use of a material with neutral pH, high dissolution capacity, and no re-precipitation issues.

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.

Phosphonate scale inhibitors (SIs) are commonly applied for barite scale prevention in oilfields. Their inhibition efficiency (IE) is affected by the barium sulphate saturation ratio (SR) of the brine mix as well as in 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+) can vary significantly for different phosphonate species. This paper presents novel IE experimental results for phosphonate scale inhibitors DETPMP and HMTPMP (pentaphosphonates), OMTHP (hexaphosphonate) and HMDP (tetraphosphonate). Minimum Inhibitor Concentration (MIC) levels for each SI are established using a wide range of brine mixing ratios which changes (i) barite saturation ratio and precipitate mass; (ii) molar ratio of Ca/Mg and (iii) the ionic strength in the brine mix. The phosphonate SIs were categorised into two types based on their IE/MIC behaviour: Type 1 (e.g. DETPMP and OMTHP) are affected principally by SR and are rather less sensitive to Ca2+/Mg2+and Type 2 (e.g. HMTPMP and HMDP) which are severely affected by brine Ca2+/Mg2+ as well as SR. To demonstrate these effects conclusively, a series of IE experiments are presented with varying brine mix but at a fixed Ca2+/Mg2+ ratio in which the MIC level using both types of phosphonate SI then correlates very well with the barite saturation ratio. In addition, we find the MICs of both types of SI are much lower in the fixed (higher Ca2+/Mg2+ratio) case experiments, compared to the base case – due to the beneficial effect of higher [Ca2+]. The effects observed are important for field application of phosphonate SIs since they show how the various species are sensitive to the changing scaling problem as the %SW increases, in terms of both SR and Ca2+/Mg2+ratio.

Inorganic scale (carbonate, sulphate and sulphides) formation can be predicted from thermodynamic models and over recent years better kinetic data has improved the prediction of such scales in field conditions. However these models have not been able to predict the observed deposition where flow disturbances occur, such as at chokes, tubing joints, gas lift valves and safety valves. This can lead to unexpected failures of critical equipment such as downhole safety valves (DHSV’s), and operational issues such as failure to access the well for coiled tubing operations due to tubing restrictions. In recent years it has been recognised that the turbulence found at these locations increases the likelihood of scale formation and experiments have been able to demonstrate that increased turbulence also impacts the minimum scale inhibitor concentration required to prevent scale. One of the industry standard test methods used to screen inhibitors for sulphate scale inhibition is the static bottle test. In this paper the ‘static’ bottle test method is modified to investigate the effects of increasing levels of turbulence on the formation of strontium sulphate scale at a fixed brine composition. Using this modified method it has been possible to demonstrate the impact of varying turbulence on the performance of two common generic types of scale inhibitor (phosphonate and vinyl sulphonate co-polymer). Data on the mass of scale formed, scale morphology using SEM imaging and inhibitor efficiency will be linked to degree of turbulence and scale inhibitor functionality (nucleation inhibition vs. crystal growth retardation). This study builds on the previously published10 findings for barium sulphate which showed phosphonates were less affected by turbulent conditions by carrying out similar tests on strontium sulphate. A clear mechanistic conclusion can now be drawn for sulphate scale formation and inhibition under increasingly turbulent conditions. The findings from this study have a significant impact on the methods of screening scale inhibitors for field application that should be utilised and development of suitable inhibitors that perform better under higher shear conditions.