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A review of oilfield mineral scale deposits management technology for oil and gas production
Abstract
The presence of formation water and the treatment methods (both water flooding and chemical treatments) employed during exploration and production operations have great potential for mineral scale formation. Scale deposition poses a lot of serious threat in field production and it is a menace to production flow assurance, which in turn reduces the production flow resulting in production losses. Although oilfield scale deposit is a long standing problem, oil and gas industry are facing new challenges in managing scale deposits created during offshore exploration activities in ultra-deepwater and other harsh environments. Traditional onshore chemistries for scale inhibitions are not viable under HT/HP conditions thereby making flow assurance a critical issue for deepwater project development. An ideal management program maximizes hydrocarbon production and minimizes the cost of scale deposits control, thereby maintaining the economic viability of the operations. This paper reviews various types of mineral scale deposits as well as the thermodynamics and kinetics prediction of mineral scale formation potentials. Also, the mitigation strategies of oilfield mineral scale deposits and chemical stimulation techniques used in oil industry to improve well productivity are discussed.
... Currently, the formation of deposits of poorly soluble salts from natural and technical aqueous solutions is a fundamental problem [1][2][3][4]. Natural water extracted from oil fields and process water used in technological systems are complex aqueous solutions that contain ions of salts of inorganic compounds. Under certain conditions, for example, a decrease in pressure or an increase in temperature, or when mixing different types of waters, dissolved ions are able to form poorly soluble salts, which, in turn, form mineral deposits. ...
... Under certain conditions, for example, a decrease in pressure or an increase in temperature, or when mixing different types of waters, dissolved ions are able to form poorly soluble salts, which, in turn, form mineral deposits. These processes are considered as an undesirable phenomenon, since they lead to the need for the repair and replacement of technological equipment and, accordingly, significant costs in the production of various products [1][2][3][4]. To ensure the scale stability of aqueous solutions, various inhibitors are used to prevent the crystallization of salts; they are considered to be the most effective at reducing the formation of scale deposits on the surface of equipment and, accordingly, can increase the rate of utilization and save energy. ...
... To ensure the scale stability of aqueous solutions, various inhibitors are used to prevent the crystallization of salts; they are considered to be the most effective at reducing the formation of scale deposits on the surface of equipment and, accordingly, can increase the rate of utilization and save energy. Inhibitors are considered a special class of chemicals that interfere with the crystallization process, slowing down or stopping the formation of poorly soluble salts in aqueous systems [1][2][3][4]. ...
In this paper, we consider natural and modified polysaccharides for use as active ingredients in scale deposition inhibitors to prevent the formation of scale in oil production equipment, heat exchange equipment, and water supply systems. Modified and functionalized polysaccharides with a strong ability to inhibit the formation of deposits of typical scale, such as carbonates and sulfates of alkaline earth elements found in technological processes, are described. This review discusses the mechanisms of the inhibition of crystallization using polysaccharides, and the various methodological aspects of evaluating their effectiveness are considered. This review also provides information on the technological application of scale deposition inhibitors based on polysaccharides. Special attention is paid to the environmental aspect of the use of polysaccharides in industry as scale deposition inhibitors.
... The incompatible mixing of these saline waters would inadvertently lead to mineral precipitation followed by scale deposition [6]. As expected, calcium carbonate, calcium, barium, and strontium sulfate are the common precipitated precursors leading to scale formation in the reservoir, while calcium carbonate is the most common in oilfields [7]. ...
... Based to PARCOM (Paris Commission, 2015), environmentally-friendly SIs meet three main criteria: i) non-toxicity, ii) non-bioaccumulation, and iii) biodegradation [25]. Consequently, several environmentally viable SIs including modified organophosphorus-based, polymeric-based chemicals, natural organic molecules, and plant extracts have been developed to meet strict environmental concerns in the oil industry [7]. ...
... In other words, the samples with the specific SIs concentration which have shown the most inhibition as well as the lower ones were considered for pH adjustment. This is because the acidic environment would better mitigate precipitation [7,47]. On the other hand, basic environment may lead to more mineral precipitation. ...
This experimental study aimed at predicting firstly the critical mixing ratio of two incompatible aqueous phases of formation water and seawater by PHREEQC (pH-redox-equilibrium conditions) at temperatures of 40, 70, and 90 °C. Secondly, the performance of two green scale inhibitors (SI) of folic acid and inulin was experimentally studied through standard static jar tests in order to determine the optimum concentration and pH at which the calcite mitigation would be maximized. The optimum pH values of 4 and 6 were respectively found for folic acid and inulin, at three investigated temperatures. Interestingly, the inhibition efficiency of these SIs increased with temperature which is advantageous for the oil reservoirs. SEM (Scanning Electron Microscopy) and TGA (thermogravimetric analysis) analyses were also carried out to discern the SIs’ inhibition mechanisms and thermal performance. The SEM results showed that folic acid and inulin would inhibit precipitation under the crystal modification and threshold inhibition mechanisms, respectively. Furthermore, TGA analysis showed that these green SIs would sustain high temperatures, although their weight losses (heating rate of 10 °C /min and T < 100 °C) were almost 3.25 % and 9.15 % for folic acid and inulin, respectively.
... However, the rapid change in the temperature and pressure near the wellbore area after fracturing has already led to scaling and formation damage, especially using high-salinity fracturing fluid in dry areas. The scaling in the formation after fracturing can reduce reservoir permeability [5], severe skin damage [6], and ultimately reduced oil well production [7,8]. The Samotlor field in West Siberia of the former Soviet Union, the Foster oil field in Texas, the oil field in Louisiana, the Ujin and Retibai oil fields in the Mangyshlak region, the Changtan oil field in California, and the Burbank and Drumright oil fields in Oklahoma were all subject to scaling with various degrees, mostly of calcium carbonate and calcium sulfate [9]. ...
... The reason for adding 4% the autogenic acid SEG-C is to maintain a low-pH environment in the reservoir over the long term. The autogenic acid is the organic ester, and it can slowly hydrolyze in the formation to produce the organic acid, which can be helpful for inhibiting scale precipitation [6]. ...
... The test method is the same as the test method in Section 2.1.1. 5,6,7,8,9,10, and 11 by 0.1 wt% HCl or 0.1 wt% NaOH solutions. Then, they were placed in a water bath at 50 • C for 24 h, and the subsequent filtration titration test was the same as Section 2.1.1. ...
The injection water and formation water in the Mahu oil field have high salinity and poor compatibility, which leads to scaling and blockage in the formation or fracture propping zone during production. In this paper, a scale-inhibiting fracturing fluid system is developed which can prevent the formation of scale in the reservoir and solves the problem of scaling in the fracture propping zone at the Mahu oil field. Firstly, based on scale-inhibition rate, the performances of six commercial scale inhibitors were evaluated, including their acid and alkali resistance and temperature resistance. Then, the optimal scale inhibitors were combined with the fracturing fluid to obtain a scale-inhibiting fracturing fluid system. Its compatibility with other additives and scale-inhibition performance were evaluated. Finally, the system’s drag-reduction ability was tested through the loop friction tester. The results showed that, among the six scale inhibitors, the organic phosphonic acid scale inhibitor SC-1 has the best performance regardless of high-temperature, alkaline, and mixed scale conditions. In addition, SC-1 has good compatibility with the fracturing fluid. The scale-inhibiting fracturing fluid system can effectively prevent scaling inside the large pores in the propping zone, and a scale-inhibiting efficiency of 96.29% was obtained. The new fracture system maintained a drag-reduction efficiency of about 75%, indicating that the addition of the scale inhibitor did not cause a significant influence on the drag-reduction efficiency of the fracturing fluid.
... The influencing factors like a commingling of injection water (i.e., seawater) and formation water are the prime factors for the formation of sulfate scales, namely barium sulfate, and pressure drop in the system might cause the formation of calcium carbonate scale. Still, other factors such as pH and temperature may also play a role (Olajire 2015;Eseosa and Atubokiki 2011;Dyer and Graham 2002). ...
... Generally, scaling in the oilfield can be classified into two groups: pH dependent or pH independent (Olajire 2015;Hoang 2015). Usually, pH-dependent scales are easier remedied than pH-independent ones by diluted hydrochloric acid (HCl) treatment. ...
... Ions are abundant in all natural streams as a result of a variety of mineral dissolution. Fluid mixing in the near-wellbore matrix typically results in new fluids with cumulative ion concentrations above the minerals' solubility limits, which in short, would cause scaling (Olajire 2015). ...
Alkaline–surfactant–polymer (ASP) flooding in oil-producing formations is associated with the deposition of scales. This hazard will affect the production flow assurance, which lowers the production flow, resulting in a reduced amount of product produced. One of the approaches to managing this scale is applying a scale inhibitor (SI) downhole to production wells via a continuous injection line. However, this process involved a high dose of chemical (250–500 ppm), and research has shown that none of the SIs deployed can inhibit this scale from occurring. One of the primary reasons is the poor adsorption of scale inhibitors onto rock formation, resulting in a short squeeze treatment lifetime. Therefore, it is vital to enhance the squeeze treatment program by “modifying” scale inhibitors with nanoparticles (NPs) that will help to prolong the squeeze lifetime with a much lower minimum inhibitor concentration (MIC) of inhibitor deployed. Oilfield scale management has recently emerged as a popular research topic in nanotechnology. The rationale behind employing nanoparticles and scale inhibitors is that nanoparticle is small-sized particles, with robust surface potential, yet the surface properties and morphologies can still be altered accordingly. With this nanotechnology approach, these nano-scaled particles are manoeuvrable for their size and can reach everywhere possible. Hence, making it more straightforward to be adsorbed onto the rock surfaces. This paper reviews the formation of scales in the reservoir and various nanomaterials previous researchers have used. The nanotechnologies studied in this paper are metal/ metal oxide nanomaterials, metal phosphonate, carbon-based nanoparticles, nanoemulsions, cross-link nanoparticles, and polymeric nanoparticles; when compared to traditional squeeze treatments, many nanoproducts created for squeeze treatments have shown increased squeeze lifespan. Nevertheless, several challenges still exist in applying nanotechnology downhole and further investigation should be carried out.
... 4−8 The scale composition can contain a mixture of inorganic, organic, and biological materials in different phases. 4,6 The calcium carbonate scale is one of the most common inorganic fouling agents and is the most widespread in oil and gas production facilities. 4,5 Calcium carbonate is also a challenging experimental system for the study of the formation and growth of metastable phases, and their transformation as CaCO 3 has three metastable forms, amorphous calcium carbonate (ACC), crystalline monohydrate (CaCO 3 ·H 2 O), and hexahydrate (CaCO 3 ·6H 2 O), and three anhydrous forms, calcite, vaterite, and aragonite, in which calcite presents higher stability among these polymorphs under standard conditions. ...
... 32,33 In addition, the simulation of the formation of the particles, characterizing both the kinetic and thermodynamic aspects of the CaCO 3 produced within the fluids produced in oil and gas industries, could be used as a virtual sensor for potential monitoring and control of incrustation problems, offering a more complete tool than the pure thermodynamic simulations that are usually used as a prediction tool by the oil and gas industry. 5,6,34 With the extensively available experimental data in the literature about the influence of divalent ions on calcium carbonate formation, one could use a thermodynamic-kinetic model to introduce the effects of these ions on the individual rates and characteristics of the carbonate solids formed. For instance, introducing the slowing down of the vaterite appearance rate that can happen with the addition of magnesium or the favoring that the strontium and barium ions can produce on the calcite and aragonite polymorph appearance. ...
... This ratio was also used in the kinetic calculations as these are usually proportional to the supersaturation. 6 ...
... Impacts include reducing heat transfer efficiency, increasing pressure, decreasing flow rate, corrosion induced breakage and pipe blockages. This review focuses primarily on nuclear infrastructure, but fouling impacts on numerous industries including cooling water systems in power generation (Ibrahim and Attia, 2015), the oil and gas industry (Olajire, 2015a), drinking water distribution systems (Liu et al., 2016b), membrane-based desalination processes (He et al., 2016) and concentration operations in the mining industries (Jeldres et al., 2017). An estimate of the non-productive expenses related to fouling were 0.8 billion $US in Great Britain, 3 billion $US in Japan, and 9 billion $US in the USA Parsons, 2004a, 2004b). ...
... Conversely, carbonates (calcite, dolomite and siderite) and sulphide scales are "pH-sensitive" because their scale formation is strongly dependent on brine pH (Kan and Tomson, 2012). Some less commonly found oilfield scales include oxides, sulphides and carbonates of iron as well as calcium naphthenate scale from acidic crude oil (Olajire, 2015a). ...
... Scale inhibitors are suggested to prevent or delay the development of scale by interfering with one or multiple steps in scale formation via mechanisms including threshold inhibition, nucleation inhibition, crystal distortion and/or dispersion mechanisms (Mpelwa and Tang, 2019). Chelators can also prevent scale formation by binding or chelating to scaling cations, with compounds of the EDTA family being the most commonly used (Olajire, 2015a). A disadvantage of chelators it that they are required in stoichiometric quantities making them costly, whereas other scale inhibitors are effective at much lower dosages (typically below 10 mg/L) (Hasson et al., 2011). ...
Fouling and scaling of equipment in the nuclear industry is a significant and challenging problem that effects multiple areas across the entire nuclear fuel cycle. Consequences such as the blockage of fluid flow, accumulation of radionuclides, reduction of heat-transfer energy and enhancement of corrosion, all can have detrimental effects on safety and performance as well as incurring substantial damage and maintenance costs amounting to billions of pounds a year. This review focuses on pipelines and understanding the mechanisms of formation and radionuclide incorporation of inorganic and biological fouling, and microbially influenced corrosion (MIC) mechanisms, as well as exploring prevalent examples in the nuclear industry and parallels in the oil and gas industries. The review will also cover advancements in fouling and scale mitigation and treatment strategies, which are imperative to reduce economic loses and avoid safety hazards in nuclear as well as many other industries.
... Pipeline scaling is a common problem in the petroleum industry. [1][2][3][4] Scale in the pipeline can narrow the area of the cross-section of the conduits and increase the resistance to fluid transport. 5,6 Therefore, it is desirable to pay more attention to anti-scaling technology. ...
... The formation of scale is mainly due to the precipitation of inorganic salts such as calcium carbonate, calcium sulfate and magnesium hydroxide. 2,7 By preparing or coating materials with low surface free energy on the surface of metal pipelines, the difficulty of adhesion of scale to the surface is increased. 8 Due to their low surface free energy and very convenient processing technology, various kinds of polymeric materials have been widely used in coating the inside of the pipelines and they show unique advantages in self-cleaning and anticorrosion. ...
Anti-scaling technology for pipelines has always been a focus of oilfield industrial production. Compared with traditional metal pipes, polyethylene (PE) pipes have unique advantages in terms of corrosion resistance, surface friction resistance, and service life. In this paper, aiming at an enhancement of anti-scaling and corrosion-resistant properties, as well as increased mechanical properties, PE nanocomposites have been prepared by the introduction of modified carbon nanotubes (m-CNTs) into the PE matrix. To improve the interface compatibility of the composites, the CNTs were treated with reactive tetrabutyl titanate after nitric acid oxidation, which brings about uniform dispersion of the CNTs and intimate interface interaction. As the m-CNT fraction increases, the PE crystallinity displays a slight increase. Polarized microscopy shows that the scaling on the surface of the composite material is obviously reduced compared with pure PE, because the surface free energy of the composite material decreases. Moreover, due to the good dispersion, the composites show enhanced mechanical properties. That is, by adding 1.10 wt% CNTs, the tensile stress and impact toughness of the composites are 20.76 MPa and 37.89 kJ m⁻², respectively, increases of 15.0% and 11.9% compared with pure PE. This paper supports the idea that the crystallinity of the PE matrix can be improved by adding CNTs, thereby increasing the corrosion resistance and anti-scaling properties. This work can provide inspiration for using the methods of scale inhibition and corrosion resistance in polymer nanocomposites.
Keywords: Carbon nanotube; Nanocomposite; Polyethylene; Anti-scaling; Corrosion-resistant.
... The petroleum industry generally suffers from mineral scale formation usually caused by incompatible mixing of brines, i.e., formation water and seawater, during waterflooding as an acclaimed EOR method [1], [2]This severe problem would lead to decreased production as well as environmental effects caused by using unsafe chemicals such as SIs or removers which are mostly used to struggle with it. Therefore, the necessity of environmentally-friendly SIs have been inflicted by regulatory authorities to protect the environment as well as the mitigation of precipitation and deposition. ...
... Many studies have experimentally investigated various scale inhibitors' mechanisms [3]- [7] as well as the parameters that impact the SIs' performance [8]- [11]. The resultant findings revealed that the SIs mechanisms are generally divided into two categories of threshold inhibition and crystal modification which retard the crystal nucleation and growth, respectively [1], [12]- [14]. Moreover, the most influential parameters have been recognized as the SI's concentration, pH, temperature, and pressure as the operational regulatory conditions. ...
Higher operating costs and lower production rates in the up and downstream oil industry are commonly reported as the consequence of mineral scale formation. Subsequently, scale inhibitors (SI) are generally known as an efficient approach to overcome this severe problem. However, the employment of some SIs is hazardous to the environment due to their chemical structures and the presence of some functional groups. Therefore, the utilization of green SIs has been highly recommended. In this study, folic acid as a green SI was investigated from a theoretical perspective, although some preliminary experiments, i.e., high-temperature static tests and contact angle measurements, were done. The results revealed that folic acid could inhibit calcite precipitation through the Lewis acid-base interaction energies. Moreover, folic acid could optimally retard calcite particles from getting aggregated and further precipitated at the dose of 450 ppm.
... Pore clogging (due to aggregation) and wettability change (related to adsorption and deposition) are two effects of asphaltene precipitation that lead to decreased productivity (Ghloum et al. 2010;Vargas et al. 2010;Hasanvand et al. 2015;Mohammadi et al. 2016;Guan et al. 2018;Al-Safran 2018;Alimohammadi et al. 2019). There are numerous studies (Buckley et al. 1997;Mullins et al. 2007;Abudu and Goual 2009;Czarnecki 2009;Boek et al. 2009;Mullins 2010;Andrews et al. 2011;Pauchard et al. 2014;Sjöblom et al. 2015;Liu and Li 2015;Punase et al. 2016;Mohammadi et al. 2020) on asphaltene precipitation, deposition, and adsorption in the literature, and several review papers (Al-jabari and Husien 2007;Enayat et al. 2020;Deng et al. 2021;Ghosh et al. 2016;Olajire 2015;Subramanian et al. 2016;Zhao et al. 2018;Sadeghtabaghi et al. 2021;Yao et al. 2021) give important insights into the issue and the actions taken so far to allay the worries. ...
One of the most extensively studied flow assurance issues in the petroleum industry is the precipitation and deposition of asphaltenes. This is in part because of the molecular structure’s intricacy and the interconnected factors that influence and regulate its activity. The injection of inhibitors and dispersants, which affects the economics of crude oil production, is now the most successful strategy for preventing asphaltene problems. Throughout the crude oil supply chain, from the reservoir through the tubing and refinery systems, asphaltene is a concern. However, the area closest to the wellbore, where the highest pressure drop is seen, is the most prone to asphaltene adsorption and deposition. Thus, the goal of this study is to investigate the use of sacrificial fluids to reduce asphaltene adsorption and deposition around the wellbore. To prevent asphaltene from interacting with the rock surface and shifting the asphaltene problem into tubing, where its impact on wettability is low, polymers with functional capabilities are investigated.
The performance test (adsorption inhibition capacity), binding energy analysis, adsorption experiments (adsorption affinity, configuration, and mechanism), and fluid characterization (salinity tolerance, surface energy, and interfacial tension) of the selected novel fluids for asphaltene adsorption mitigation are presented. The investigation of ion-specific rock-fluid interactions offers great potential in the search for an effective answer to the asphaltene problem, according to the results. This was proved by the fluid levels of binding energy to carbonate rock samples and their capacity to prevent interactions between asphaltene molecules and the rock surface. These findings provide a fresh perspective on the creation of an economic strategy to deal with asphaltene issues and their effects. This study is the first to investigate a long-term fix for wettability changes caused by asphaltene adsorption on rock minerals. The findings revealed that an optimal concentration exists for the polymers under study, at which the asphaltene interaction is mitigated. More so, surface energy evaluation is observed to be a critical tool that can help to screen polymers for this application. Furthermore, the method of implementation, which could be either squeeze operation or continuous injection, is critical to the success of the remediation.
... To date, various studies have been conducted to evaluate the incompatibility of formation water and injection water 33 . Two major types of inorganic scales that are usually formed in oil reservoirs during water flooding operations are sulfate and carbonate scales 34,35 . One of the main causes of carbonate scales is usually the incompatibility of formation and injection waters mixing with different ratios of calcium and bicarbonate-rich water like seawater mixed with formation water. ...
In this study, a mechanistic and comprehensive examination of the impact of the scale formation situation of different diluted seawater levels was conducted to investigate the influence of important factors on the performance and efficiency of low salinity water. To clarify the effective participating mechanisms, scale precipitation by compatibility test, field emission scanning electron microscopy (FESEM) and energy dispersive X-ray spectroscopy (EDX) analysis, zeta potentials as surface charge, ion concentration changes, contact angle, pH, CO2 concentration, electrical conductivity, and ionic strength were analyzed. The results showed that increasing the dilution time to the optimal level (10 times-diluted seawater (SW#10D)) could effectively reduce the amount of severe precipitation of calcium carbonate (CaCO3) and calcium sulfate (CaSO4) scales. However, the reduction in CaCO3 scale precipitation (due to mixing different time diluted seawater with formation brine) and its effect on the wettability alteration (due to the change in surface charge of OLSW/oil and sandstone/OLSW) had higher impacts. The zeta potential results have shown that OLSW with optimum salinity, dilution, and ionic composition compared to different low salinity water compositions could change the surface charge of OLSW/oil/rock (− 16.7 mV) and OLSW/rock (− 10.5 mV) interfaces toward an extra negatively charged. FESEM and contact angle findings confirmed zeta potential results, i.e. OLSW was able to make sandstone surface more negative with diluting seawater and wettability changes from oil-wet toward water-wet. As a result, SW#10D was characterized by minimum scaling tendency and scale deposition (60 mg/l), maximum surface charge of OLSW/oil/rock (− 16.7 mV), and the potential of incremental oil recovery due to wettability alteration toward more water-wetness (the oil/rock contact angle ~ 50.13°) compared with other diluted seawater levels.
... To minimize these impacts, efforts have been driven in the development of effective scale management [2][3][4][5][6], which includes mechanical and chemical methods [7]. Different types of scale inhibitors (Sis) can prevent or diminish scale formation by inhibiting the nucleation step on surfaces and/or the bulk growth of salt crystals in valves, pipelines, oil pathways, and pumps [8]. ...
The oilfield urges efficient and low-cost scale management. Specifically, simple and accurate methods to determine the active component of scale inhibitors at the point of need can be a game-changer by preventing their misuse, ultimately reducing time and expenses. To address this bottleneck, we describe an electrochemical method for the indirect monitoring of phosphonate (PO3) scale inhibitors based on advanced oxidation processes principles. PO3 species are first converted to phosphate (PO4) via UV exposure (3 min) in the presence of an oxidant, which is then allowed to react with ammonium molybdate to instantaneously form an electroactive phosphomolybdate complex. Next, the electrochemical detection of this complex is proceeded by interrogating scalable miniaturized three-electrode Au sensors, with SU-8 photoresist film individually delimiting the active area of the electrodes to guarantee their reproducibility. An average error of 7.3% was obtained over the analyses of standard samples (H3PO4) for 6 months by different operators. The approach reached accuracies from 81.5 ± 8.3 to 100.3 ± 15.5% when assessing nine commercial scale inhibitor samples. These results are an encouraging indicator that our method is a promising tool for on-site, fast, and accurate quality control of phosphonate scale inhibitors.
... Moreover, the activities of HCO 3 − and Ca 2+ increase at higher temperatures, resulting in an elevated effective collision between HCO 3 − and Ca 2+ and thereby facilitating the formation of CaCO 3 scales [69]. However, the introduction of sulfonic and amide groups in MVTE enhances its high-temperature resistance compared to VE, which is crucial for the production of an effective antiscalant [21,76]. Therefore, MVTE can be effectively applied to circulating cooling water systems. ...
Natural-polymer-based antiscalants for various calcium scales have recently received significant attention due to their prominent structural features, such as hydroxyl, amino, and organic acids, as well as their environmental friendliness and widespread availability. In this study, a novel green antiscalant, namely modified valonia tannin extract (MVTE), was synthesized using valonia tannin extract (VTE), itaconic acid (IA), and 2-acrylamido-2-methylpropanesulfonic acid (AMPS). The structure of MVTE was characterized by Fourier transform infrared spectroscopy (FT-IR). The crystal morphology, structure, and surface elementary composition of CaCO3 were analyzed using scanning electron microscopy (SEM), X-ray diffraction (XRD), and X-ray photoelectron spectroscopy (XPS), respectively. Results indicate that MVTE with the best anti-scale performance is prepared when the valonia dosage is 2.5 g, the initiator dosage is 6 wt.%, the reaction temperature is 75 °C, and the reaction time is 3.5 h. Moreover, MVTE shows significantly improved resistance to temperature and alkalinity compared to VE. Results from SEM, XRD, and XPS demonstrate that MVTE can interfere with the regular growth of CaCO3 crystals through chelation, dispersion, and lattice distortion. This effect results in the generation of vaterite, which inhibits the deposition of CaCO3. Meanwhile, the molecular dynamics (MD) simulation was employed to further explore the anti-scale mechanisms at an atomistic level. The results illustrate that interaction energies originate from ionic and hydrogen bonds between MVTE and calcite, which ultimately improve the anti-scale performance of MVTE. In conclusion, MVTE can be an excellent antiscalant in circulating cooling water systems.
... 133,134 The incompatible brine of different salt chemistries (for example, formation water with low content of sulfate and seawater with sulfate ion content) would initiate mineral precipitation (like calcium sulfate precipitates) on mixing. 135 Pressure−temperature conditions, formation water chemistry, pH, and ionic strength are the critical factors responsible for scale formation. The sulfates of barium, strontium, or calcium; iron oxides; calcium, magnesium, or iron carbonates; and iron sulfides are the frequently encountered scales in oil and gas production systems (as presented in Figure 10). ...
... Many case histories of oil well scaling by calcium carbonate, calcium sulfate, strontium sulfate, and barium sulfate have been reported (Mitchell et al. 1980;Lindlof and Stoffer 1983;Vetter et al. 1987;Shuler et al. 1991;Liu et al. 2009;Olajire 2015;Liang et al. 2019;Murtaza et al. 2022). Problems in connection to oil well scaling in Russia, where scale has seriously plugged wells and is similar to cases in North Sea fields, have also been raised (Mitchell et al. 1980). ...
The chief source of the oilfield scale is the mixing of incompatible waters. This study demonstrated that mixing the reservoir of Mishrif formation (Halfaya oilfield) with six types of injection water sources, including Tigris River water, producing water formation, Gulf seawater, Marshes water, Middle Kirkuk formation water, and Main Outfall Drain water (AL-Masab AL-Aam Channel), leads to the formation of salt crusts that cause the reduction of reservoir rock permeability. According to the Piper diagram, the Mishrif formation water of all extant water samples was of the sodium chloride type (NaCl), except for HF-81, which was between (NaCl) and mix (CaMgCl) type. A geochemical simulation model of water alignment (PHREEQC) was used to simulate this problem, and it revealed the mineral scaling from mixing processes. These minerals precipitate in rock pores and clog them, which then cause damage to the petrophysical properties of the reservoir and prevent the passage of liquids. Results showed that the best water types used for injection are Middle Kirkuk formation water, followed by the general downstream, then Gulf seawater, but treatment before injection is needed. The study of geochemical modeling method can help to better understand scaling issues by efficiently identifying the best injection water from various selected types with the lowest possible cost, which in turn improves oil production.
... Recently, various polymeric inhibitors have been studied over the past few years [4,[16][17][18][19][20][21][22]. Iron sulfide particles treated with polymers remained amorphous after 10 days of aging at 72 ℃, explaining the high efficiency of polymeric inhibitors [23,24]. ...
This article reports on poly (acrylamide-co-malonic acid) and poly(AM-co-MAc) copolymers that inhibit the iron sulfide scale. The iron sulfide scale is considered as one of the most challenging oilfield scales to dissolve or inhibit once formed due to the fast deposition kinetics and low solubility criteria. We present the synthesis, characterization, and testing of poly(AM-co-MAc) that inhibits iron sulfide formation by hindering nucleation growth and preventing particles from settling. A strictly anoxic apparatus was designed and used to evaluate the performance of the synthesized inhibitor. The influence of temperature, pH, and brine composition was also quantified. The results indicated that poly(AM-co-MAc) inhibits iron sulfide formation and nucleation growth under various conditions. The inhibitor effectively maintained iron sulfide particle separation at specific dosages, lowering its ability to cluster. Maximum efficiency of 92% was recorded at 60 °C and 1% volume inhibitor concentration. DFT calculations confirmed the inhibitive properties of poly(AM-co-MAc) via binding energy calculations. Compared to recently reported inhibitors, poly(AM-co-MAc) proves to be safer concerning toxicity properties. This study provides theoretical and technical insights for a novel chemistry solution for the metal-sulfide scale.
... Chemical scale accumulation of insoluble mineral salts on water pipeline equipment is a significant problem in the oil field. The mineral deposits can be barium sulfate, calcium carbonate, calcium sulfate, iron sulfide and strontium sulfate contributing to faults inflow restriction, equipment wear, costly repair, and maintenance interruptions, thus decreasing the efficiency of chemical processing production [1,2]. ...
Surface facilities including tubing and valves at the oilfield have been plagued by mineral scale deposits, which are constitute of calcium carbonate (CaCO3). Penta-potassium diethylenetriaminepentaacetic acid salt (DTPA-K5) has a higher affinity for the metal cations complexes during the chelation process. The eight complexing sites (five carboxylate and three amines) empower the metal ion interactions. This work investigated the molecular dynamics simulations between the DTPA-K5 with the calcium carbonate, CaCO3 scale. The interaction was performed through molecular dynamic (MD) simulation using condensed phase optimised molecular potentials for atomistic simulation studies (COMPASS) force field and the Ewald summation method in Material Studio. The simulation trajectory files examined the intermolecular interactions for radial distribution function (RDF). The simulation shows strong DTPA-K5 with calcium interactions, which revealed the metal ion complexes contributing to the chelation process through the reactive carboxylic and amine functional groups, which were O7 == Ca at radius, r, 2.25 Å with g(r) of 10.09 and N1 -- Ca at radius, r, 2.25 Å with g(r) 2.51.
... In scale precipitation, there are different negative points, including higher operational costs, lower production rates, and detrimental environmental effects when using hazardous scale inhibitors to inhibit scaling. These particles in the porous media restrict fluid flow through the reservoir or reduce the diameter of production tubing by formation of a thick film in the tubing (Olajire 2015). Scale precipitation causes different damages, including the blockage of equipment, acceleration of corrosion, energy leakage, and accidents, which have noticeable impacts on the safety of production. ...
Scale precipitation in petroleum equipment is known as an important problem that causes damages in injection and production wells. Scale precipitation causes equipment corrosion and flow restriction and consequently a reduction in oil production. Due to this fact, the prediction of scale precipitation has vital importance among petroleum engineers. In the current work, different intelligent models, including the decision tree, random forest (RF), artificial neural network (ANN), K-nearest neighbors (KNN), convolutional neural network (CNN), support vector machine (SVM), ensemble learning, logistic regression, Naïve Bayes, and adaptive boosting (AdaBoost), are used to estimate scale formation as a function of pH and ionic compositions. Also, a sensitivity analysis is done to determine the most influential parameters on scale formation. The novelty of this work is to compare the performance of 10 different machine learning algorithms at modeling an extremely non-linear relationship between the inputs and the outputs in scale precipitation prediction. After determining the best models, they can be used to determine scale formation by manipulating the concentration of a variable in accordance with the result of the sensitivity analysis. Different classification metrics, including the accuracy, precision, F1-score, and recall, were used to compare the performance of the mentioned models. Results in the testing phase showed that the KNN and ensemble learning were the most accurate tools based on all performance metrics of solving the classification of scale/no-scale problem. As the output had an extremely non-linear behavior in terms of the inputs, an instance-based learning algorithm such as the KNN best suited the classification task in this study. This argumentation was backed by the classification results. Furthermore, the SVM, Naïve Bayes, and logistic regression performance metrics were not satisfactory in the prediction of scale formation. Note that the hyperparameters of the models were found by grid search and random search approaches. Finally, the sensitivity analysis showed that the variations in the concentration of Ca had the highest impact on scale precipitation.
... These nanoparticles align themselves with the EM field when subjected to high-frequency EM radiation, resulting in high-frequency particle motions that heat up the surrounding region through friction. [9][10][11][12]. ...
Nanotechnology's use in the oil and gas business is on the rise, as indicated by the number of studies conducted in recent years. This expansion has been fueled by the desire to produce additional game-changing technology that can address the industry's present difficulties. Several nanoparticles of various sizes and concentrations have been employed in a variety of studies. The study's scope included the use of nanotechnology in drilling and hydraulic fracturing fluids, oil well cementing, enhanced oil recovery (which included a transport study as well as foam and emulsion stability), corrosion inhibition, logging operations, formation fines control during production, heavy oil viscosity reduction, hydrocarbon detection, methane release from gas hydrates, and drag reduction in porous media. The stability of nanoparticles in a liquid medium and their transportability in reservoir rocks has been recognized as problems. Researchers utilized viscosities to assure stability, as well as surface-treated nanoparticles to aid stability and transportability. The majority of nanotechnology publications in the oil and gas business to far have been reports of laboratory experiments; consequently, further field trials are necessary for continued advancement of nanotechnology in this area. Nanoparticles are typically expensive, thus using the lowest nanoparticle concentration feasible while still obtaining an acceptable degree of desired performance can save money. As a result, optimization studies should be considered in future nanotechnology research.
... Inorganic scaling is a major issue in many industrial and domestic applications and involves the precipitation of metal carbonates, sulfates, oxides and hydroxides from solution induced by temperature changes, evaporation or pressure decrease [1]. These incrustations usually form at heat exchanger surfaces, inside pipes, and on membranes during distillation (MD) or reverse osmosis (RO), drastically reducing the efficiency of desalination units [2][3][4], heat exchangers [5], and facilities for oil and gas recovery [6,7]. Feed water (pre)treatment is routinely used to mitigate scale formation in water-intensive systems such as desalination units or home care appliances [3,7,8], including: (a) pH adjustment of the solution, (b) use of ion exchangers to remove scale-forming ("hardness") ions like Ca 2+ or Mg 2+ , (c) addition of chelating agents, or sequestrants, causing a decrease of the effective supersaturation due to complexation of the scale-forming ions, and/or (d) addition of small amounts of water-soluble additives that actively suppress scale formation. ...
The detrimental effects of inorganic scaling in industrial and domestic applications are often mitigated with scale inhibitors. Increasing environmental awareness and stringent regulations require developing more sustainable antiscalants. Testing of suitable candidates is often the rate-limiting step in development cycles, therefore we developed a high-throughput methodology to rapidly evaluate the antiscaling potential of new additives under different application conditions. Using this method we determined the performance of two potential green additives – a chelating agent and a threshold inhibitor – in delaying CaSO4 precipitation over a wide range of supersaturations, temperatures and salinities. The threshold inhibitor strongly delayed CaSO4 scaling, but its performance is highly dependent on the physicochemical conditions, with the appropriate application window comprising low salinities and mild temperatures. In contrast, the chelating agent showed a lower inhibiting capacity, but its performance remained relatively constant throughout the entire matrix of physicochemical conditions. Noteworthy, we also observed that at intermediate salinities the absolute induction time for CaSO4 precipitation is dramatically prolonged, offering a sustainable strategy to mitigate scaling. Overall, our method allows simultaneously benchmarking the scaling kinetics and testing the scale-inhibiting performance of additives, providing a direct route to a more rational design of antiscaling technologies.
... As such, methods of modeling mineral solubility, which is the driving force for scale formation, date back to the early 1900s and are still being improved today. When available, mineral scale models can be used to (i) avoid mixing of incompatible brines, (ii) determine if scale inhibitors are needed and (iii) predict when scale removal maintenance is required [2,3]. Some common mineral scales are sulfate-based (Ba, Sr, Ca), oxides/hydroxide-based (Fe, Mg), and carbonate-based (Ca, Mg, Fe) [2]. ...
Methods of predicting mineral scale formation have evolved over the years from simple empirical fittings to sophisticated computational programs. Though best practices can now solve complex multi-phase, multi-component systems, they are largely restricted to temperatures below 300 °C. This review examines critical gaps in existing mineral scale modeling approaches as well as strategies to overcome them. Above 300 °C, the most widely used model of standard thermodynamic functions for aqueous species fails when fluid densities are below 0.7 g cm−3. This failure occurs due to the model’s reliance on an empirical form of the Born equation which is unable to capture the trends observed in these high temperature, low density regimes. However, new models based on molecular solvent-solute interactions offer a pathway to overcome some of the deficiencies currently limiting high-temperature and high-pressure mineral scale predictions. Examples of the most common scale prediction methods are presented, and their advantages and disadvantages are discussed.
... There are different scales encountered in the oilfield. They include: Calcium carbonate, calcium sulphate, strontium and barium, sulphide scales (iron (II), zinc, and lead (II) salts), sodium chloride, iron, silicon sediment and other insoluble solids [34,35]. ...
The petroleum industry includes the global processes of exploration, extraction, refining, transportation and marketing of natural gas, crude oil and refined petroleum products. The oil industry demands more sophisticated methods for the exploitation of petroleum. As a result, the use of oil field chemicals is becoming increasingly important and has received much attention in recent years due to the vast role they play in the recovery of hydrocarbons which has enormous commercial benefits. The three main sectors of the petroleum industry are Upstream, Midstream and Downstream. The Upstream deals with exploration and the subsequent production (drilling of exploration wells to recover oil and gas). In the Midstream sector, petroleum produced is transported through pipelines as natural gas, crude oil, and natural gas liquids. Downstream sector is basically involved in the processing of the raw materials obtained from the Upstream sector. The operations comprises of refining of crude oil, processing and purifying of natural gas. Oil field chemicals offers exceptional applications in these sectors with wide range of applications in operations such as improved oil recovery, drilling optimization, corrosion protection, mud loss prevention, drilling fluid stabilization in high pressure and high temperature environment, and many others. Application of a wide range of oilfield chemicals is therefore essential to rectify issues and concerns which may arise from oil and gas operational activities. This review intends to highlight some of the oil field chemicals and their positive applications in the oil and gas Industries.
... 14 Thus, it is better to inhibit their occurrence, which can be achieved using chemical inhibitors such as chelating agents, 12,15,16 regulation of thermodynamic conditions of temperature and pressure, or by proper formulation of injected brine. 1,17 The mechanisms of scale formation in reservoirs are (i) change in pressure and/or temperature, (ii) mixing of incompatible brines with different sulfate and cation (Ca 2+ and Ba 2+ ) concentrations, and (iii) brine evaporation and consequent increase in salt concentration. 18 These scales impede flow and damage the reservoir and flow equipment, 19 with the problem more intense at elevated temperatures. ...
Scale formation and deposition in the subsurface and surface facilities have been recognized as a major cause of flow assurance issues in the oil and gas industry. Sulfate-based scales such as sulfates of calcium (anhydrite and gypsum) and barium (barite) are some of the commonly encountered scales during hydrocarbon production operations. Oilfield scales are a well-known flow assurance problem, which occurs mainly due to the mixing of incompatible brines. Researchers have largely focused on the rocks' petrophysical property modifications (permeability and porosity damage) caused by scale precipitation and deposition. Little or no attention has been paid to their influence on the surface charge and wettability of calcite minerals. Thus, this study investigates the effect of anhydrite and barite scales' presence on the calcite mineral surface charge and their propensity to alter the wetting state of calcite minerals. This was achieved visa -vis zeta-potential (ζ-potential) measurement. Furthermore, two modes of scale control (slug and continuous injections) using ethylenediaminetetra-acetic acid (EDTA) were examined to determine the optimal control strategy as well as the optimal inhibitor dosage. Results showed that the presence of anhydrite and barite scales in a calcite reservoir affects the colloidal stability of the system, thus posing a threat of precipitation, which would result in permeability and porosity damage. Also, the calcite mineral surface charge is affected by the presence of calcium and barium sulfate scales; however, the magnitude of change in the surface charge via ζ-potential measurement is insignificant to cause wettability alteration by the mineral scales. Slug and continuous injections of EDTA were implemented, with the optimal scale control strategy being the continuous injection of EDTA solutions. The optimal dosage of EDTA for anhydrite scale control is 5 and 1 wt % for the formation water and seawater environments, respectively. In the case of barite, in both environments, an EDTA dosage of 1 wt % suffices. Findings from this study not only further the understanding of the scale effects on calcite mineral systems but also provide critical insights into the potential of scale formation and their mechanisms of interactions for better injection planning and the development of a scale control strategy.
... Scale deposition is the bane of the oil and gas industry. These oilfield scales often contain calcium carbonates and sulfates, including barium sulfate, iron sulfides, and many others [1,2]. Calcium carbonate (CaCO 3 ) is one of the most frequently occurring scales [3]. ...
The calcium carbonate (CaCO3) scale is one of the most common oilfield scales and oil and gas production bane. CaCO3 scale can lead to a sudden halt in production or, worst-case scenario, accidents; therefore, CaCO3 scale formation prevention is essential for the oil and gas industry. Scale inhibitors are chemicals that can mitigate this problem. We used two popular theoretical techniques in this study: Density Functional Theory (DFT) and Ab Initio Molecular Dynamics (AIMD). The objective was to investigate the inhibitory abilities of mixed oligomers, specifically acrylamide functionalized silica (AM-Silica). DFT studies indicate that Ca2+ does not bind readily to acryl acid and acrylamide; however, it has a good binding affinity with PAM and Silica functionalized PAM. The highest binding affinity occurs in the silica region and not the –CONH functional groups. AIMD calculations corroborate the DFT studies, as observed from the MD trajectory that Ca2+ binds to PAM-Silica by forming bonds with silicon; however, Ca2+ initially forms a bond with silicon in the presence of water molecules. This bonding does not last long, and it subsequently bonds with the oxygen atoms present in the water molecule. PAM-Silica is a suitable calcium scale inhibitor because of its high binding affinity with Ca2+. Theoretical studies (DFT and AIMD) have provided atomic insights on how AM-Silica could be used as an efficient scale inhibitor.
Interactions of ions with ionically bonded minerals such as barite (BaSO4) influence the fate and transport of the ions, while the factors that control the sorption of toxic oxyanions on barite remain elusive. In this study, the sorption of arsenate, selenate, and molybdate on the barite (001) surface was examined at pH ∼5 using in situ crystal truncation rod analysis, resonant anomalous X-ray reflectivity, and atomic force microscopy. The results show that arsenate and selenate mainly incorporate into the top monolayer of barite, while molybdate primarily adsorbs above the surface. The sorption coverage of arsenate is greater (by ∼100%) than that of selenate but similar to that of molybdate. The different incorporation coverages between arsenate and selenate can be explained by their different protonation states at pH 5. The incorporated arsenate may be stabilized by hydrogen bonds between arsenate and oxygen atoms of neighboring sulfate compared to selenate, which exists predominantly in the deprotonated state. The adsorption of molybdate above the surface probably stems from a surface-induced oligomerization, as the anion and the oligomer may be too large for incorporation. Our observation of these different sorption mechanisms demonstrates how the physicochemical properties of the anions control the selective uptake of the toxic metals on the dominant surface of the ionically bonded mineral barite.
The dissolution of quartz mineral in sandstone reservoir due to chemical enhanced oil recovery (cEOR) processes, such as alkaline surfactant polymer (ASP) flooding has resulted in the scaling of silica and silicates around the wellbore formation and in the production wells. These scales can block and hinder the flow of producing fluids if left untreated. This will lead to reduced production rates as well as equipment damages eventually. The adsorption and squeeze performance of developed scale inhibitors that made up of polyamidoamine (PAMAM) dendrimers and pteroyl–L–glutamic acid (PGLU) was assessed in this paper. The results were compared to diethylenetriamine penta(methylene phosphonic acid), a commercial phosphonate scale inhibitor known as DETPMP. The crushed Berea sandstone core was soaked in scale inhibitor solutions for static adsorption test. Core flooding was performed to investigate the adsorption and retention of scale inhibitors in sandstone formation. The prediction of scale inhibitor squeeze performance was simulated based on core flooding data obtained. Laboratory results reveal PAMAM–2–PGLU scale inhibitor that comprises second generation PAMAM dendrimer exhibits the highest adsorption and retention in sandstone core. On top of that, the permeability of sandstone core was also increased with the treatment of PAMAM–PGLU scale inhibitors. SQUEEZE IV software also predicted that PAMAM–PGLU scale inhibitors yielded longer squeeze lifetime than DETPMP scale inhibitor. Both experimental and modelling results showed a good fit in terms of adsorption and squeeze lifetime. In this paper, the tested PAMAM–PGLU scale inhibitors demonstrate better adsorption, retention, and squeeze lifetime in sandstone formation. Although commercial scale inhibitors are effective at a wide range of reservoir conditions, the disposal of phosphonate scale inhibitors has raised concern due to their toxicity and low biodegradability. Hence, these developed PAMAM–PGLU scale inhibitors could be offered as environment–friendly and effective alternatives.
This research examined the use of 75 nm zinc oxide nanoparticles (nano ZnO) and polyethylene butene (PEB) to decrease the viscosity of Nigerian waxy crude oil. The rheology of the crude oil was assessed by measuring the viscosity and shear stress of samples containing PEB at 500, 1000, 2000, 3000, 4000 or 5000 ppm and nano ZnO at 1, 2, 3 or 4 wt% between 10 and 35 °C at shear rates from 1.7 to 1020 s−1. Rheological modeling indicated that a power law pseudoplastic model was the best fit for the experimental data, giving a regression coefficient of 0.99. The addition of these inhibitors induced Newtonian fluid behavior in the crude samples such that the shear stress-shear rate relationship plots were linear at all temperatures. The optimum concentrations of the inhibitors in this study were 2000 ppm PEB (providing a 33% viscosity reduction) and 1 wt% nano ZnO (providing a 26% viscosity reduction). A combination of these additives at these concentrations provided a synergistic effect and gave a greater viscosity reduction of 41%. This work demonstrates that a blend of ZnO nanoparticles and PEB can improve the flowability of waxy crude.
The deposition of inorganic scale in pipelines used in the exploration of oil on marine platforms caused by precipitation of metal ions is one of the main problems related to...
There are few measurements of barium sulfate (BaSO4) solubility in water above 373 K available in the literature. BaSO4 solubility data at water saturation pressure are scare. The pressure dependence on BaSO4 solubility has not previously been comprehensively reported for the pressure range 100-350 bar. In this work, an experimental apparatus was designed and built to measure BaSO4 solubility in aqueous solutions under high-pressure (HP), high-temperature (HT) conditions. The solubility of BaSO4 was experimentally determined in pure water over the temperature range from T = (323.1 to 440.1) K and pressures ranging from p = (1 to 350) bar. Most of the measurements were done at water saturation pressure: six data points were done above the saturation pressure (323.1-373.1 K) and 10 experiments were conducted at water saturation (373.1-440.1 K). The reliability of the extended UNIQUAC model and results generated in this work was demonstrated by comparing with the scrutinized experimental data reported in the literature. The model gives a very good agreement with BaSO4 equilibrium solubility data, demonstrating the reliability of the extended UNIQUAC model. The accuracy of the model at high temperature and saturated pressure due to data insufficiencies is discussed.
During oil and gas exploration and production operations, it is common for organic and inorganic deposits interact from changes in the phases of the fluids. The use of inorganic scale inhibitors and hydrate inhibitors are preventive measures adopted to reduce any of these problems. However, the presence of hydrate inhibitors induces supersaturation, leading to the precipitation of salts present in the produced water. This work investigated the effect of different chemical inhibitors ((2-hydroxyethyl)iminobis(methylene phosphonic acid)—HMPA, sodium diethyltriamino pentamethylene phosphonic acid—NaDETPMP, ethanol, monoethylene glycol, and glycerol) on calcium carbonate scale at different temperatures and inhibitor concentration under pressurized conditions using the Dynamic Scale Loop method. Scanning electron microscopy analysis was also performed to evaluate the morphology of the crystals formed. In addition, a kinetic model was employed to understand the process variables in the scale profile. The results showed that the HMPA scale inhibitor presented higher performance when compared to the NaDETPMP inhibitor. An increase in scale time and a reduction in scale rate were observed. On the other hand, the effects associated with the addition of hydroxylated compounds influenced the process. High concentrations of hydrate inhibitors promoted an increase in viscosity. The simultaneous addition of inhibitors reduced the growth kinetics of the precipitated particles and the formation of agglomerates, keeping the solids in suspension, and making it difficult for the crystals to adhere into the internal surface of the test tubbing. The synergistic effect between the additives favored the reduction of particle size and promoted changes in crystal morphology.
This chapter briefly discusses the main challenges facing the flow assurance related areas in the oil and gas industry. It also provide simple fundamental definitions to machine learning vocabulary to introduce to machine learning terms.
One of the most extensively studied flow assurance issues in the petroleum industry is the precipitation and deposition of asphaltene. This is in part because of the molecular structure's intricacy and the interconnected elements that influence and regulate its activity. The injection of inhibitors and dispersants, which affect the economics of crude oil production, is now the most successful tactic used. Anywhere throughout the crude oil supply chain, from the reservoir through the tubing and refinery systems, there is an asphaltene concern. However, the area closest to the wellbore, where the greatest pressure decrease is seen, is the most prone to asphaltene adsorption and deposition. Thus, the goal of this study is to investigate how new sacrificial fluids might be used to reduce asphaltene adsorption and deposition around the wellbore. To prevent asphaltene from interacting with the rock surface and shifting the asphaltene problem into the tubing where its impact on wettability is low, the sacrificial fluid/rock ion-specific interactions are investigated.
This is a groundbreaking attempt to relocate the asphaltene issue from the wellbore into the tubing, where it does not affect the reservoir's wettability. The performance test (adsorption inhibitive capacity), binding energy analysis, adsorption experiments (adsorption affinity, configuration, and mechanism), and fluid characterization (salinity tolerance, surface energy, interfacial tension) of the chosen novel fluids for asphaltene adsorption mitigation are presented. The investigation of ion-specific rock-fluid interactions offers great potential in the search for an effective answer to the asphaltene problem, according to the results. This is proven by the fluids’ levels of binding energy to carbonate rock samples and their capacity to prevent interactions between asphaltene molecules and the rock surface. These studies’ findings open a fresh perspective into the creation of an economical strategy to deal with asphaltene issues and their effects. This study is the first to investigate a long-term fix for wettability changes brought on by asphaltene adsorption on the mineral rock. This entails looking for a fluid that, when used as a remediation fluid in cases of asphaltene deposition, has a stronger affinity for the rock than asphaltene and has the potential to remove asphaltene. Additionally, for the first time in the state of the art of remediation fluid design, realistic environmental conditions are considered in the search for this fluid.
Scale is a production problem that occurs in the water system. Scale is a deposit formed from the crystallization and deposition of minerals contained in water formation. The formation of scale occurs due to the incompatibility of the fluid mixture, changes in pressure, temperature, and pH. Generally, scale is formed around perforations, subsurface equipment such as tubing, and on surface production equipment such as wellheads, so that it can result in decreased production rates because the flow of oil from the formation to the surface is hampered. Therefore, it is necessary to make efforts to handle the scale problem, both in the form of preventive and countermeasures when scale deposition has occurred in the field. Preventive measures are preventive measures that can be carried out by using scale control chemicals (scale inhibitors), as well as by maintaining the ionic component of the water that is injected into the well. In this study, the formulation of the problem that will be proposed is how to deal with scale problems that occur in XY field by predicting scale deposits and taking countermeasures through scaling index calculation and literature study which are limited only to reservoir, bottom hole, and wellhead. Through the calculation of the Stiff-Davis and Oddo-Thompson Method, the Scaling Index value is obtained from each scale formed so that it can be seen the types of scales formed in the field. Furthermore, through the Scale Software simulation, the Scaling Index value, the concentration of the formed scale, and the compatibility of the injection water were obtained. From the analysis of formation water through the calculation of the Scaling Index using the Stiff-Davis and Oddo-Tompson methods, it is known that the tendency of the scale formed is the CaCO3, CaSO4 and SrSO4 scales with high positive SI and Is values, with a range between 2.25 to 3.96 of CaCO3, 2.10 to 2.73 of CaSO4, 1.27 to 1.41 of SrSO4. From the calculation of the Scaling Index using the Scale Software, it is also found that there is a tendency to form a scale of CaCO3, CaSO4 and SrSO4 with relatively high values varying from 1.52 to 1.67 of CaCO3, 0.05 to 0.28 of CaSO4, 0.58 to 1.02 of SrSO4. In this XY field, the maximum scale deposits values of CaCO3, CaSO4 and SrSO4, were also obtained, which were 232 mg/L of CaCO3, 410 mg/L of SrSO4, 606 mg/L of CaSO4. From the Scale Software simulation, the scale deposits of CaCO3 of mixing formation and injection waters are lower than the scale deposits of CaCO3 of formation water. Therefore, the injection water is compatible to be injected into the reservoir. From the literature study, the effort to control scale that has formed in the well is carried out chemically, namely through the implementation of acidizing continuously using 15% HCl, (NH4)CO3 water solution, a phosphate-type scale inhibitor, 1500 ppm hydrolysed polyacrylamide, and operate under 1500 psi and 170 deg F.
A method is proposed for the production of an inhibitor of salt deposition based on a polyelectrolyte complex, including an anionic natural polymer (sodium lignosulfonate) and a cationic synthetic polymer (polydiallyldimethylammonium chloride) as initial components. A stable polyelectrolyte complex was produced by selecting the molar ratios of the anionic and cationic components by impedance spectroscopy, which involves measurement of the dependence of an electrochemical cell on the frequency of the alternating current. The effectiveness of the polyelectrolytic complex as inhibitor of salt deposition in waters with various compositions under conditions of rising temperatures was demonstrated experimentally.
Calcium carbonate is a pH dependent inorganic mineral scale that is influenced by CO2 and H2S partitioning. CaCO3 prediction must therefore include accurate modelling of the aqueous phase and all hydrocarbon phases present. pH dependent scale prediction challenges and the development of a rigorous procedure for generation of more accurate results were previously published. This procedure has now been applied to an onshore oilfield in Southeast Asia for assessment and management of CaCO3 scaling.
A rigorous scale prediction workflow was applied to ‘at-risk’ field producers that showed CaCO3 scaling at and/or downstream of the wellhead choke valve (WHCV). By inputting relevant field data into an integrated PVT/scale prediction code and using the correct procedure, it was possible to evaluate scaling potentials. A series of sensitivity studies allowed well ranking based on the predicted severity of their scaling potentials. The approach validated mechanistic hypotheses for scale development in prolific low watercut, ultra-high CO2, sour, high temperature producers. Close matching of predictions with actual wellhead scaling events provided the basis for improved full-field scale management, and strategic targeting of onsite scale mitigation resources.
Target field producers exhibited 0.2% to 25% watercut and presented different degrees of scale precipitation at and/or downstream of the WHCVs. Following well scaling potential assessment, each producer was subject to a series of sensitivity studies to identify (i) how scaling changed with time and (ii) provide focus on the key inputs that most impacted predictions. The initial findings, considering measurement errors (normal field variability), were surprising as key input parameters such as gas phase CO2 and produced water calcium ion concentration appeared to show minimal influence on the final scale prediction results for these wells; even more remarkable considering typical production featured very low salinity produced brine and ultra-high CO2 sour field gas. Focus was therefore shifted to field temperatures, pressure profiles and volumetric flow rates. Of importance is that the selection of ‘critical parameters’ is field specific and that the example presented here shows the variability in scale precipitation at different stages of well production, and how the scaling potential (SR and mg/L) must be evaluated together with the predicted daily theoretical mass of scale (kg/d). This is important in the study of wells with such variable water cut.
The following paper demonstrates the value of a rigorous and systematic approach to the prediction of CaCO3 scale, which is often investigated using inappropriate or incomplete methodologies. In this work the authors demonstrate how the technique can address and explain important operational issues and provide solid foundations for implementing and indeed improving the field scale management program.
Mineral scale formation is a major operational challenge in oil and gas fields that always comes with a high cost. Thus mineral scale must be detected early and managed to avoid detrimental impacts. Scale management involves preventing scale formation and removing the formed scale. Scale prevention can be achieved by means of operational, chemical, and nonchemical methods. Operational means are based on optimizing the process parameters to avoid solids precipitation and deposition the chemical methods are based on using chemical inhibitors; and the nonchemical methods are based on using physical methods that change the fluid properties to be nonscaling. Scale removal methods are based on chemical methods using dissolvers, and nonchemical methods using physical and mechanical means. In this chapter, mineral scale management is addressed, and a comprehensive scale management strategy is outlined in light of recent advances.
Numerous well operations, including water injection, varying stimulation approaches, and enhanced oil recovery (EOR) techniques are implemented during the production period in order to maintain the longevity of hydrocarbon production. However, reservoir formation, production, and injection facilities are often impacted by these treatments. Well operations induce inorganic scale to form near-wellbore regions and in various production and injection structures. Consequently, the deposition of scales hinders assessing an optimum hydrocarbon production as their precipitation on formation, various surface, and downhole equipment leads to many problems, including pressure decrement, formation damage, and operational failure of subsurface equipment.
As a control measure to prevent scale precipitation downhole squeeze treatment is commonly used in the petroleum industry. By applying a squeeze treatment, a scale inhibitor solution is introduced into a formation above the formation pressure, allowing the scale inhibitor to get into the deep into near-wellbore formation. Downhole squeezing allows scale inhibitors to adsorb on the internal rock surface to avoid the settling down of scale precipitates. Thus, the study of adsorption of different types of inhibitors, such as chelating agents, polymeric inhibitors, and polyphosphates on formation is becoming necessary. The study incorporated several experimental techniques, including dynamic adsorption experiments using coreflooding setup, ICP-OES (Inductively Coupled Plasma - Optical Emission Spectrometry), and ζ-potential measurements targeting evaluation of adsorption of aminopolycarboxylic acids in carbonate rocks and iron precipitation in calcite mineral. Potential precipitation of iron in varying pH environments and causing the formation of iron-containing scales was assessed through ζ-potential measurements.
The findings reveal that the concentration of aminopolycarboxylic acids plays a significant role in their adsorption on carbonate rocks. The adsorption is also affected by different factors, such as the presence of salts. The results of ζ-potential measurements showed that iron (II) and iron (III) precipitation is controlled by the pH environment in calcite minerals. The treatments with 20 wt% ethylenediaminetetraacetic acid (EDTA) and diethylenetriamine pentaacetate acid (DTPA) produced the highest adsorption capacity in carbonate rock samples by inhibiting 84% and 85% of iron (III) ions, respectively. The encountered permeability damage in the adsorption tests was between 25% and 32%. Moreover, the presence of the salts considerably decreased the adsorption of EDTA and caused almost 20% more permeability reduction.
Unlike the conventional testing methods for inhibitor adsorption, a novel experimental setup, coreflooding was used during the inhibitor adsorption, and scale inhibition in carbonate formation.
An important oilfield issue is the formation of a wide range of scales during oil and gas well operations. Oilfield scales hinder assessing an optimum hydrocarbon production as their precipitation on formation, various surface, and downhole equipment leads to many problems, including pressure decrement, formation damage, and operational failure of subsurface equipment. One type of these scales is the iron sulfide scale and based on studies in the Khuff reservoir, iron sulfide scales are likely to deposit on production tubing and rock formation. Therefore, it becomes essential to restrain the occurrence of iron sulfide scale using environmentally friendly chemicals in production tubing, water injection wells, and near-wellbore formation.
The primary focus of this work is the prevention of iron sulfide scale deposition in carbonate formations during water injection applications. Iron sulfide scale inhibition was studied through dynamic inhibition adsorption experiments. In contrast to conventional experiments, for scale inhibition and adsorption of chelating agents (static bottle, dynamic filter tube tests) and simulation studies, a novel experimental setup (coreflooding experiments) was proposed to study the inhibitor adsorption. Broad concentrations of high-pH aminocarboxylic acids (such as ethylenediaminetetraacetic acid (ETDA) and diethylenetriamine pentaacetate acid (DTPA)) were examined (10 wt%, 15 wt%, and 20 wt%), at temperatures of 120°F and 200°F.
Results of the study revealed that iron (III) precipitation is an obvious threat causing severe formation damage in carbonate rocks by significantly decreasing the rock permeability. Adsorption of chelating agents on limestone rocks highly depends on their concentrations. Specifically, an increase in the concentration of EDTA and DTPA at elevated temperature conditions resulted in higher adsorption. The inhibition experiments revealed that 20 wt% EDTA could significantly decrease the iron sulfide scale precipitation.
Unlike the conventional testing methods for scale formation and prevention, a novel experimental setup - coreflooding during the inhibitor adsorption, formation, and inhibition of iron sulfide scale in carbonate formation was used. The main advantage of the method is the consideration of permeability alteration happening due to the scale formation. Another point is that in previous studies, various scale control chemicals and experimental approaches have been suggested for iron sulfide scale inhibition, and polymeric, phosphonate, and sulfonated co-polymeric inhibitors were used. However, the subgroup of chelating agents - aminocarboxylic acids, was used in this study.
Scale deposition, especially in the petroleum industry, has always been a serious issue because of its potential safety hazards and huge economic cost. However, conventional scale-resistant strategies based on mechanical descaling and chemical detergents can't feed the urgent demand for energy saving and environmental protection. Herein, we report a bioinspired long-term oil collectible mask (BLOCK)-a microspine coating with the synergistic effect of anti-adhesion and oil collection, displaying sustainable scale resistance towards oilfield-produced water. Inspired by pitcher plants, the oil layer as a liquid barrier inhibits scale deposition by changing the underwater scaling micro-environment from liquid/solid/solid to a liquid/solid/liquid triphase system. Oil droplets are collected by cacti-inspired microspines to enhance oil layer stability. Compared with stainless steel, the BLOCK coating shows ca. 98% reduction even after 35 days in artificial produced water. This strategy could be utilized to design integrated functional materials for conquering complex environments such as oil recovery and transportation.
Hydrocarbon production operations include water injection, varying stimulation approaches, and enhanced oil recovery techniques. These treatments often affect reservoir formation, production, and injection facilities. Such sorts of well operations cause the formation of organic and inorganic scales in the near-wellbore region and various production and injection structures. Downhole squeeze treatment is commonly used as a control measure to prevent scale precipitation. A scale inhibitor solution is introduced into a formation by applying a squeeze treatment. The method allows scale inhibitors to adsorb on the internal rock surface to avoid settling down the scale precipitates. Thus, the study of adsorption of different types of inhibitors to prevent scale formation on the reservoir rock through the execution of downhole squeeze treatment is becoming necessary. This study incorporated different experimental techniques, including dynamic adsorption experiments of chelating agents employing a coreflooding setup, inductively coupled plasma-optical emission spectrometry (ICP-OES) to inhibit the formation of iron-containing scales in limestone rocks, and ζ-potential measurements targeting determination of iron precipitation in varying pH environments on calcite minerals. The influence of the inhibitor soaking time and salt existence in the system on chelating agent adsorption was also evaluated in the coreflooding experiments. The findings based on the coreflooding tests reveal that the concentration of chelating agents plays a significant role in their adsorption on carbonate rocks. The treatments with 20 wt % ethylenediaminetetraacetic acid (EDTA) and 20 wt % diethylenetriaminepentaacetic acid produced the highest adsorption capacity in limestone rock samples by inhibiting 84 and 85% of iron(III) ions, respectively. Moreover, the presence of the salts (CaCl2 and MgCl2) considerably decreased the adsorption of 10 wt % EDTA to 56% (CaCl2) and 52% (MgCl2) and caused nearly 20% more permeability reduction, while more inhibitor soaking time resulted in comparably higher adsorption and lesser permeability diminution. The results of ζ-potential measurements showed that the pH environment controls iron(II) and (III) precipitation, and iron(III) starts to deposit from a low pH region, whereas iron(II) precipitates in increased pH environments in calcite minerals.
Sulphide scales have low solubility and are mostly observed in deep high temperature/high pressure (HTHP) reservoirs. Particularly, squeeze treatment for HTHP wells in sandstone reservoir, has always been challenging due to the thermal degradation of polymeric scale inhibitors followed by poor retention properties. To this date, identifying a squeezable scale inhibitor for sulphide scale deposition that compiles with these conditions is an ongoing research topic. A thermally stable Polyaniline-Co-Polymer based scale inhibitor (PANI-Co-Polymer SI) has been developed, characterised, and tested. Adsorption isotherms analysis, thermogravimetric analysis (TGA), dynamic tube blocking tests (TBT) and scanning electron microscopy (SEM) analysis have been carried out in order to assess the efficiency against zinc sulphide (ZnS) scale as well as adsorption and desorption properties of the newly formulated product. Based on adsorption isotherms analyses, PANI- Co-Polymer SI shows high adsorption on sand particles that follows the Freundlich adsorption model. Product performance was also evaluated by TBT and TGA. Monitored differential pressure values over a one-hour period, shows a minimum effective dose (MED) of <5mg/L for ZnS and thermal stability up to 385° C, respectively. For a better interpretation of the inhibition mechanism by PANI-Co-Polymer SI, transmission electron microscopy (TEM) images and selected area electron diffraction (SAED) were implemented. Results indicate secondary crystal nucleation and growth disruption for ZnS. These results show that PANI-Co-Polymer SI could be a successful candidate to be used as a squeeze treatment for preventing ZnS scaling issues under HTHP conditions.
Long life-time anti-scaling is one key problem in the oilfield extraction process. Encapsulating the scale inhibitor into microspheres is an effective approach to achieve this effect. Ethylene diamine tetra methylene phosphonic acid sodium (EDTMPS), a scale inhibitor in salt form and with high water-solubility, was successfully encapsulated into polymethyl methacrylate (PMMA) microspheres by the S/O/W solvent evaporation method. The influence of synthesis various parameters on the morphology and particle size was investigated. Release and scale inhibition behaviors of functional microspheres were studied, respectively. Results indicated that the functional microspheres with a regular spherical shape and good dispersibility were obtained. The microspheres possessed encapsulation efficiency exceeding 88% and ideal sustained-release properties (up to 120 hours) ensuring sustainable scale inhibition. The realization of long life-time anti-scaling was attributed to (1) EDTMPS’s sustained-release and (2) the combined effect of chelation and lattice distortion. These novel functional microspheres have a promising application prospect in the field of industrial scale inhibition.
Scaling usually causes serious problems in daily life and industrial production. Currently, developing passive anti-scaling coatings has shown promises to overcome this problem. In this work, we fabricated a scalable and robust bio-inspired organogel(BIO) coating, showing dynamic scale resistance in the oil/brine mixture. The oil layer of the BIO coating was utilized as a barrier to inhibit scale nucleation and reduce scale adhesion. The mechanical strength of the coating was optimized by regulating nanoparticle contents. Moreover, the universality of scale resistance was demonstrated by varying the types of nanoparticles, oils and scales. Compared with commercial pipeline materials, such as copper, this BIO coating significantly reduces scale deposition after 240-h scaling test(ca. 93% reduction). Therefore, this study designs scalable and robust organogel coatings for sustainable scale resistance, which may be used for practical application in oil production.
Scale formation is the precipitation of sparingly soluble inorganic salts from an aqueous medium. Oilfield scales are formed by precipitation from the water that occurs naturally in reservoir rocks, or when two incompatible waters meet downhole, leading the produced water to become oversaturated with scale components. The deposition of scale can occur on any surface, and once that happens, it will get thicker over time unless an intervention of some sort is in place. Alongside corrosion and gas hydrates, the precipitation of sparingly soluble inorganic salts is a major issue in the upstream oil industry. Scale can cause a reduction in formation porosity and permeability by blocking the pore throat in the near-wellbore or the well. Scale inhibitors are polymeric and/or nonpolymeric organic compounds, which dissolve into formation water to prevent scale deposition. The aim of this chapter is to provide an overview of different synthetic approaches to manufacturing various oilfield scale inhibitors. In addition, the scale inhibition performance, calcium tolerance, thermal stability, biodegradation, and squeeze treatment properties of these scale inhibitors have been reported.
Mineral scale is the hard inorganic solid deposited from aqueous solution due to local supersaturation. Scaling issue is one of the most serious water-related operational problems in various industries, especially in oilfield operations. Scale deposition can cause production downtime and pose severe threats to the personnel safety and operational integrity. Composite scales are the scale particles composed of multiple mineral phases. While extensive efforts have been made to investigate the behaviors of precipitation and formation of single scale, knowledge of thermodynamics and kinetics of composite scales is still very limited. The presence of scaling ions would accelerate the kinetics of cocrystallization and coprecipitation of composite scales since these ionic species might provide the seeding points for nucleation. The information presented in this chapter suggests that scale formation behaviors solely from experimental and computational data on pure scale formation process might incorrectly estimate the severity of composite scaling which commonly takes place at actual operational conditions. Although the difference in scaling propensity between composite fouling and single scale has been proved to exist, efficient control strategy specifically designated to manage composite scale is very limited and future studies are required on this regard. Nevertheless, based on the elaboration in this Chapter, a number of experimental efforts have been reported to address scaling threat associated with composite scales. The review in this chapter provides comprehensive and informative details on the thermodynamics and kinetics of several common composite scales.
The development of the scale layers in oil and gas operation results in production losses and equipment instability because of pipeline blockage, energy leak, corrosion acceleration and severe accidents which will impact the safety of production. Among many types of scales, calcium carbonate and calcium sulfate are considered the most frequent, prominent and terrible. On the other hand, cellulose is a class of natural polymers and also contains abundant functional groups including hydroxyl, carboxyl, and amino groups, resulting in good chelation and dispersion effects. They possess good physical and chemical properties, thermal stability, and biodegradability, abundantly available and inexpensive which make them promising compounds for the creation of "green" oil field reagents, including scale inhibitor. In this study, we tested two types of biodegradable polymers named hydroxyethyl cellulose (HEC) and carboxymethyl cellulose (CMC) for application as calcium carbonate and mixed carbonate and sulfate inhibitors. There are three methods carried out, starting from the thermal stability test, static bottle test, and dynamic scale loop test. The inhibition performance tests were done at temperatures of 50°C, 70°C, and 90°C. The inhibitor concentration was varied from 10, 50, 100, 1000 until 10000 ppm. The results indicate that both HEC and CMC have the potency to be used as inhibitors for these two types of scales. Both results from the static bottle test and dynamic scale loop test indicate that HEC and CMC were able to inhibit the formation of the tested scale, yet they have not been able to completely inhibit 100% of scale formation.
Corrosion prevention is an imponant aspect of oil and gas production. The pipelines are protected from internal corrosion by the application of corrosion inhibitors. In recent years the application of 'green chemistry' principles to the area of corrosion inhibitors has attracted lot of attention which has resulted in the reduction/elimination of toxic inhibitors and the production of 'green' or low toxicity environmentally friendly formulations. In order to develop inhibitors with low or zero environmental impact there is a need to review the requirements which these green inhibitors have to fulfill under the various regulations that exist in various countries. A number of corrosion inhibitors have been developed with low environmental impact while preserving the inhibitor efficiency. The test methods and development of environmentally friendly corrosion inhibitors under different regulations are discussed. A brief account of the Paris Commission (PARCOM), UK, Norwegian regulations are also given.
In a deepwater west African field, the relatively small number of high-cost, highly productive wells, coupled with a high barium sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery.
The nature of the well-completion strategy in the field (frac packs for sand control) had resulted in some wells with higher than expected skin values owing to drilling-fluid losses, residual fracture gel, fluid loss agents, and fines mobilization within the frac packs.
The paper will present how the challenges of managing impaired completions and inorganic scale forced innovation in terms of when to apply both stimulation and scale-inhibitor packages to deepwater wells. This paper will outline a novel process for non-conventional batch chemical applications where bullhead stimulation treatments have been displaced deep into the formation (>20 ft) using a scale inhibitor overflush. Not only does this benefit the stimulation by displacing the spent acid and reagents away from the immediate wellbore area, but the combined treatment provides a cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments. The four field treatments that were performed demonstrate how these coupled applications have proven very effective at both well stimulation/skin reduction and scale-inhibitor placement before and after seawater breakthrough. The term “squimulation” is used by the local operations team to describe this simultaneous squeeze-and-stimulation process.
Many similar fields are currently being developed in the Campos basin (Gulf of Mexico) and west Africa, and this paper presents a good example of best-practice sharing from another oil basin.
Soap deposits, which can manifest as emulsion soaps (carboxylates) or hard deposits (naphthenates), are an increasingly recognized cause of some unique flow assurance and crude marketing problems in oilfield processes.This paper illustrates the physical and chemical drivers for the generation of soap scales in a number of differing and challenging production system environments.Mitigation options for the successful treatment of soap scales are also discussed. Where possible, data presented in this paper are taken from field trials in order to illustrate these drivers and the impact of successful mitigation strategies.
An understanding of the key fluid characteristics allows pre-screening of fluids from new field developments that are likely to develop naphthenate/soap deposits and allows diagnosis ofthe likely soap scaling problems. The critical fluid characteristics required for the generation of naphthenate soaps are different from those required for generation of carboxylate soaps.An empirical approach to predicting the degree of risk for soap generation, based on oil and produced water properties, can be adopted, although there are knowledge and data gaps that increase the uncertainty of this approach.
Physical parameters, such as pressure, are known to influence soap generation. However, other physical parameters that are key in the design and operation of an oil-field process can also influence the soap severity. These parameters include temperature, shear, electrostatic fields, water cut and fluid-fluid incompatibility; examples of each are discussed. This information can be used in the design stages of an oil-field process where engineers must think beyond the conventional process designs.
Despite the fact that the impact of a soap problem can be considerably reduced by adjustment of physical design and operating parameters, chemicals are usually required to provide complete mitigation of soap. Chemical mitigation (acid and non-acid) guidelines are discussed with field examples and the need for a chemical management and monitoring programme.
Introduction
Soap solids are formed when metals present in the reservoir water react with the napththenate or carboxylate groups to form salts (or soaps), which are generally sodium or calcium salts. These salts have been known to occur in a number of forms in the oilfield production system, including:Dissolved salts that can and do affect the sales value of the crude by giving increased metal ion contents (e.g. calcium).Viscous emulsions from wells and interfacial emulsion pads in separators, which hinder efficient oil-water separation and can become waste sludges/slops in Crude Oil Terminals.Hard, solid scale deposits that restrict production render controls systems inoperable and cause discharge water and export oil qualities to deteriorate.
Recognition of soap scales in production systems is becoming increasingly common.Such materials if not properly identified, understood and handled, will reduce the efficiency of a number of critical oilfield operational activities.These activities include oil dehydration, fluid desalting, produced and waste water treatment and disposal, oil storage and export.
Greenish-brown soap sludge is formed in significant quantities during production of oil from the Serang field, offshore East Kalimantan, Indonesia. The sludge forms upon cooling of oil in subsea pipelines and onshore terminal storage tanks. This interfacial sludge is comprised of entrained free oil, water and solids, and is stabilized by an acyclic "metal carboxylate" soap. In the absence of fluid treatment, removal and disposal of the sludge is tedious, expensive, and represents significant un-recovered oil. The soap also adversely affects discharge water quality.
The sludge has been characterized to understand its formation mechanism, so that remedial actions can be taken to mitigate its deposition.1 A variety of analytical methods indicated that the "soap" emulsion consists of about 30% water, 50% oil, and 20% of C28 – C30 carboxylate salts in sodium form. The "soap" is stabilized by fatty acid-Na-HCO3 complexation, and results from the reaction of long chain fatty acids in oil with sodium bicarbonate-rich waters containing significant volatile fatty acids.
Laboratory and field tests have demonstrated that the sludge can be dissolved by low dosages of commercially available sludge dissolving agents containing combinations of acids. An acid demulsifier, consisting of acetic acid in an aromatic solvent mixture, and a non-acid demulsifier, consisting of ethoxylates and alcohol, have been injected into Serang produced fluid arriving at the onshore Santan terminal since August 2002. The demulsifiers have significantly reduced sludge deposition in oil storage tanks and water-handling facilities. In addition to "dissolving" sludge, incremental oil is recovered, which offsets chemical treatment and sludge disposal costs. Existing sludge is treated with chemicals and hot centrifuging to minimize waste and optimize oil recovery.
The ultra-high temperature (150-250°C), pressure (1,000-2,000 bar, 15,000 to 30,000 psi) and TDS (>300,000 mg/L) in deepwater oil and gas production pose significant challenges to scaling control due to limited knowledge of mineral solubility, kinetics and inhibitor efficiency at these extreme conditions. Prediction of thermodynamic properties of common minerals is currently limited by lack of experimental data and inadequate understanding of modeling parameters. In this study, a new apparatus was built to test scale formation and inhibition at high temperatures and pressures. Solubilities of two common minerals, barite and calcite, were tested at temperature up to 250°C, pressure up to 1,500 bar (22,000 psi) and ionic strength up to 6m in solutions with elevated concentrations of mixed electrolytes (e.g., calcium, magnesium, sulfate and carbonate) representing the maximum range of interferences expected (95%CI) in oil and gas wells. As an attempt towards experimentally determining mineral solubility at high temperature, pressure and salinity, not only does this study contribute to the extremely limited data base, but it also provides a reliable approach for evaluating and adjusting model predictions at extreme conditions. Predictions by a thermodynamic model based on Pitzer's ion interaction theory were evaluated using experimental data. The dependence of Pitzer's coefficients for ion activity coefficients on temperature and pressure was examined and incorporated into the scale prediction model, whose prediction is consistent with both experimental and literature data at all conditions tested.
Calcium sulphate and barium sulphate are two major scales experienced in the oil and gas fields, especially when sea water breakthrough in the waterflood supported HTHP wells. Normally, studies have been focused on a single scale component. Seldom studies have focused on the co-deposition of calcium sulphate and barium sulphate. The importance of interference between calcium sulphate and barium sulphate deposition in the field, especially for the HTHP wells, has been ignored.
In this paper, the interference between calcium sulphate and barium sulphate deposition has been studied based on a field case in the North Sea. The mechanisms of co-deposition have been addressed using both scale prediction and laboratory tests. Environmentally acceptable scale inhibitors have also been developed.
The scaling tendency and mass deposition of calcium sulphate and barium sulphate have been predicted with sea water breakthrough at different levels. The difference between calcium sulphate and barium sulphate, and the consequences of both types of scale deposition are discussed.
Dynamic scale loop tests have been carried out. It demonstrated that a small amount of barium sulphate deposit substantially accelerates the co-deposition of barium sulphate and calcium sulphate. Linked to the scale prediction, the mechanism of co-deposition of calcium sulphate and barium sulphate has been addressed.
Several scale inhibitors, including phosphonate and polymer based inhibitors, along with an amine based polymer have been tested under the worst case scaling condition. Environmentally acceptable scale inhibitors have been developed and are suitable for squeeze application.
This paper will give a comprehensive study of co-deposition of calcium sulphate and barium sulphate, including scale prediction, laboratory evaluation, mechanism discussion and inhibitor selection. It will contribute to understand calcium sulphate and barium sulphate scale deposition in HTHP wells and find effective inhibitors for field application.
Calcium naphthenate deposition is among the most challenging obstacles to high production regularity for oilfields where acidic crude oils are produced. Until now it has generally been acknowledged that the deposit is made up of calcium soaps of the naphthenic acids in the crude oil, though with a slight overrepresentation of the lighter acids. In this paper, however, we demonstrate that this is not the case. Through a combination of several analytical techniques – the most important being Potentiometric Titration, LC/MS, NMR, and VPO – the ARN acid has been identified as the dominating constituent of these deposits. The ARN acid is a family of 4-protic carboxylic acids containing 4 - 8 unsaturated sites (rings) in the hydrocarbon skeleton with mole weights in the range 1227 – 1235 g/mol. The mole weight of the homologous ARN acids series are 1227, 1229, 1231, 1233, 1235 (basic structures) + n×14 (n = number of additional CH2-groups in hydrocarbon skeleton). The ARN acid with mole weight 1231 has C80H142O8 as empirical formula.
The present paper describes the different analytical methods leading to the ARN acid discovery. Furthermore it discusses possible ARN structures and methods for quantitative ARN detection in crude oils. The ARN acid has proved to be the main component in naphthenate deposit from oilfields offshore Norway, Great Britain, China and West Africa. The implications of the discovery to current calcium naphthenate treating strategies will be briefly discussed.
A thermodynamic model for the description of vapor–liquid–solid equilibria is introduced. This model is a combination of the extended UNIQUAC model for electrolytes and the Soave–Redlich–Kwong cubic equation of state. The model has been applied to aqueous systems containing ammonia and/or carbon dioxide along with various salts. Model parameters valid in the temperature range 0–110°C, the pressure range from 0–100 bar, and the concentration range up to approximately 80 molal ammonia are given. The model parameters were evaluated on the basis of more than 7000 experimental data points.
It is shown that gas-phase data on hydrated H/sup +/ and OH/sup -/ ions from mass spectrometry can be used to calculate the ionization product for water at high temperature and at high enough pressure to allow relating these results with those directly measured near 1000 K and 0.5 g cm/sup -3/. The thermodynamic properties of the hydrated H/sup +/ and OH/sup -/ are discussed and the heat capacity is compared with results calculated from the Born equation for an appropriate region of temperature and pressure.
The potential for the cell Pt,H/sub 2/,CO/sub 2/exclamationM(HCO/sub 3/)/sub 2/,MCI/sub 2/,CO/sub 2/(aq)exclamationAgCl,Ag with M = Mg and Ca was measured over a wide range of molalities at 298.15 K. The data were interpreted by the mixed-electrolyte equations of Pitzer and Kim to yield the ion-interaction parameters for Mg/sup 2 +/, HCO/sub 3//sup -/, and for Ca/sup 2 +/, HCO/sub 3//sup -/. The trace activity coefficients of M(HCO/sub 3/)/sub 2/ in MCI/sub 2/ and in NaCl are calculated.
Relations for the design of polyphosphate well packs to prevent carbonate scale deposition have been effectively applied in South Sumatran oil fields.
Introduction
The deposition of calcium carbonate scale on surface and subsurface production equipment creates an operation problem in many oil fields. The formation water in which the carbonate-scale-forming components are initially dissolved becomes supersaturated with calcium carbonate as a result of the drop in pressure during production. The continuous flow of pressure during production. The continuous flow of a supersaturated solution through the production equipment results in the growth of a dense layer of calcium-carbonate crystals.
For a scale layer to be built up, the supersaturated formation water should contact the walls of the production equipment. The tendency for scale to be production equipment. The tendency for scale to be deposited, therefore, will be low, if the crude has a low water cut and if the water is finely dispersed in the oil. A scale problem will occur, if at a high water cut part of the water is present as free water. The rate of scale deposition win then be approximately proportional to the rate of free water production. proportional to the rate of free water production. Depending upon where the formation water becomes supersaturated, scale may be deposited in the flow line only, in both flow line and tubing, and in some cases even in the perforations and in the formation near the wellbore.
In the South Sumatran fields (Indonesia) the main difficulties encountered due to the deposition of calcium-carbonate scale have been restriction of flow through tubings and flow lines, wear and abrasion of plungers and liners, and stuck plungers or wellhead plungers and liners, and stuck plungers or wellhead valves. So far, the only methods of combating the scale problem have been routine acidizing and additional well pulling. As for the pumping wells, it was estimated that some 50 percent of the total well-pulling effort was directly attributable to scale deposition.
The most promising alternative was to prevent the deposition of calcium carbonate scale by means of chemicals. Inorganic polyphosphates such as sodium hexametaphosphate and trisodium polyphosphate are known to retard the formation of scale by the "threshold action". They are adsorbed on specific faces of the crystal nuclei and thus prevent crystal growth, thereby stabilizing supersaturation. Polyphosphates are effective at very low concentrations Polyphosphates are effective at very low concentrations (a few ppm), and far less than stoichiometric quantities are required to keep the scaling ions in solution. Recent investigations on barium sulfate scale have confirmed this mechanism.
The types of polyphosphate mentioned can be applied as concentrated aqueous solutions either squeezed into the formation, lubricated down the annulus or injected via macaroni string. Several squeeze jobs with polyphosphate solutions have been carried out in the South Sumatran fields, however, with disappointing results. Lubrication down the annulus and injection through a macaroni string were not considered attractive in this area because of the kind of equipment and the degree of supervision these techniques require.
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With the advance of new exploration and production technologies, oil and gas production has gone to deeper and tighter formations than ever before. These developments have also brought challenges in scale prediction and inhibition, such as the prevention of scale formation at high temperatures (150-200°C), pressures (1,000-1,500 bar), and total dissolved solids (TDS) (>300,000 mg/L) commonly experienced at these depths. This paper will discuss (1) the challenges of scale prediction at high temperatures, pressures, and TDS; (2) an efficient method to study the nucleation kinetics of scale formation and inhibition at these conditions; and (3) the kinetics of barite-crystal nucleation and precipitation in the presence of various scale inhibitors and the effectiveness of those inhibitors. In this study, nine scale inhibitors have been evaluated at 70-200°C to determine if they can successfully prevent barite precipitation. The results show that only a few inhibitors can effectively inhibit barite formation at 200°C. Although it is commonly believed that phosphonate scale inhibitors may not work for high-temperature inhibition applications, the results from this study suggest that barite-scale inhibition by phosphonate inhibitors was not impaired at 200°C under strictly anoxic condition in NaCl brine. However, phosphonate inhibitors can precipitate with Ca 2+ at high temperatures and, hence, can reduce efficiency. In addition, the relationships of scale inhibition to types of inhibitors and temperature are explored in this study. This paper addresses the limits of the current predition of mineral solubility at high-temperature/high- pressure (HT/HP) conditions and sheds light on inhibitior selection for HT/HP application. The findings from this paper can be used as guidelines for applications in an HT/HP oilfield environment.
To satisfy the current environmental legislation for produced water disposal, the only alternative seems to lie between the re-injection on site of the produced water or the use for the squeeze treatment of biodegradable chemicals. Two different industrial "green" scale inhibitor families, i.e., synthetic polyamino-acides and carboxylated plant polysaccharides, were compared to current inhibitors (phosphonates or polyacrylates) in their ability to reduce carbonate and sulfate scale formation. The potential implementation of the green products in squeeze treatments implied a full compatibility with the injection water, i.e., seawater. In the moderate sulfate scaling case, the 80-90% limit of BaSO4 inhibition (based on remaining soluble Ba++ ions) was reached by 10 to 50 ppm of DETPMP, 50 ppm of CMI 2.5 and 100 ppm of CMI 2.0 (CMI is Carboxy Methyl Inulins). Comparative Jar and Tube Blocking Tests showed that these "green inhibitors" might exhibit competitive inhibiting efficiencies in both carbonate and sulfate scale deposit formation. Preliminary static and dynamic adsorption/desorption experiments performed with the CMI inhibitor on limestone core material showed that its behavior is quite similar to that of a polyacrylate with nevertheless superior adsorbing properties. It is possible to prepare, at least in the laboratory, a completely "green" water in oil invert emulsion, containing from 10 to 100 g/L of inhibitor, stable at room temperature, and which is broken under higher reservoir temperature conditions.
ASP flooding in Daqing oilfield commenced from 1980s. To date, industrial pilot tests have been carried out in three blocks. The averaged recovery was increased by 20%. On the other hand, scaling issue caused high frequent pump failures. Large amount of scale building up in the producers wellbore and downhole equipments with high speed, which resulted in the averaged running life of lifting system decreased from 599 days of water flooding period to 60 days. Further more, some producers’ running lives were only around 30 days, leading to higher production cost and lower production rate as well.
Study indicated that, the scaling principle and scale composition in producing wells differed from each other and was difficult to be predicted accurately. In this study, after tracking and measuring the ion in produced fluid for the whole process from water flooding, polymer flooding to ASP flooding and analyzing composition of the scale on different parts of scaling well, the criterion and distinguishing chart of scaling tendency had been set up initially. The criteria were applied in 102 wells in ASP flooding area, the accordance rate was more than 90 percent. Based on that, scaling inhibition technology was timely performed for predicted scaling wells, and the running lives were increased from 40 days to above 200 days. This paper presented the process of the study and is greatly helpful for APS flooding in commercial scale.
ASP (alkali-surfactant-polymer) flooding improves recovery rate dramatically. However, scaling problem happens in artificial lift systems and causes pump sticking in sucker rod pumps and the average pump running time decrease from 500 days to 37 days. By analyzing the constituents and characteristics of scales from ASP production wells and experimenting with simulating produced liquid, characteristics and mechanism of silicon containing scale forming are researched. The results show that Ca2+, Mg2+, Al3+, polyacrylamide, surfactant and silicon influence the ASP scales structures and forming processes. The ASP scales have the characteristics of absorbing and sticking. Basing on describing of scaling characteristics, mechanisms and the pump structures, the reasons for pump sticking are analyzed. Pump sticking which caused by scaling between the plunger and barrel occurs when the sucker rod pump is sucking, hot water is circulating or the pump is stopping. When the well is shut down, one major reason of pump sticking is scale particles set down, stick and pack in the anti-sand groove. When a great deal of hot water is circulating in the well bore, liquid viscosity lowers and scale particles set down speed increases also. The slow-dissolved solid scale-inhibitor SY-2 and anti-scale pump with long plunger-short barrel are developed and applied in field. Through these methods applications, the pump running time have been prolonged and good results have been achieved.
The mechanism, reaction kinetics, and rate equation of the naphthenate soap precipitation are determined by means of experimental and theoretical investigations. Such information may be important for controlling and minimizing the well productivity loss by naphthenate soap precipitation in petroleum reservoirs. This was accomplished by three means: a) Static bottle tests were conducted to determine the precipitation rate at various pH and temperature conditions, b) particle size growth of the naphthenate soap precipitates was investigated under static conditions to determine the governing growth mechanism, and c) core flow tests were run to determine the effect of the naphthenate soap precipitation on permeability impairment in porous media. The naphthenate soap precipitation rate was correlated with respect to the considered parameters based on a power-law expression. The measured particle size data indicated the growth of particle size with time. Finally, the core flow tests allowed the determination of the impact of the naphthenate soap precipitation in porous media in terms of the permeability impairment and damage ratio. The results of these studies may be instrumental in avoiding or minimizing formation damage problems associated with the naphthenic acid containing petroleum reservoirs.
A new and reliable Oilfield Scale Prediction Model (OSPMod) has been developed and is presented. Unlike the available models which predict only scaling potential using thermodynamics and limited solubility data, OSPMod predicts the potential and deposition profile based on extensive thermodynamic and kinetic data. The model uses experimental solubility data in NaCl, MgCl2, CaCl2, and their mixtures, and in natural oilfield brines to determine the saturation index. Critical saturation indices beyond which scaling occurs have been established for the common oilfield scales (BaSO4, SrSO4, CaSO4 nH2O, and CaCO3). The model uses the flow characteristics and experimental kinetic data to predict the scale deposition profile from the bottomhole to the surface, once the critical saturation index is exceeded. The model has been developed as a menu-driven, user-friendly software. It is applicable to all the common oilfield scales and provides several input, computation and output options. Graphic presentation of results is a useful feature of OSPMod. The accuracy, reliability, and key features of the model are illustrated in the text with oilfield and test well cases.
Biodegradable scale inhibitors have been developed that provide excellent inhibition of barium sulfate scale and that meet regulatory requirements for application in the North Sea and in other sensitive marine environments. These inhibitors are in compliance with the " yellow-banded?? classification issued by the Norwegian sector of the North Sea, meeting ecotoxicity, bioaccumulation, and biodegradation standards. Using turbidity and dynamic tube-blocking protocol, the inhibitors have been shown to provide barium sulfate inhibition comparable to their non-biodegradable equivalents.
Introduction
Deposition of scale on production equipment impairs the production of oil and gas in reservoirs, down hole, surface and injection operations. Scale inhibitors are often a significant portion of the aqueous based chemical stimulation package used in either the stimulation and/or completion of oil/gas wells. Although highly effective, a number of the chemistries used for these applications-polyacrylates, polyphosphonates, and polysulphonates-have low biodegradability and are unable to meet increasingly strict environmental legislation.
A series of improved polymeric scale inhibitors have been developed in accord with the ecotoxicity, bioaccumulation, and biodegradablity standards set by the Convention for the Protection of the Marine Environment of the North-East Atlantic (OSPAR.. These inhibitors are highly effective for control of a variety of alkaline-earth scales and are suitable for use in scaling environments ranging from mild supersaturation to severe conditions where difficult-to-control barium sulfate scales may form. These products perform comparably to their non-biodegradable equivalents while exceeding the standards required for " yellow-banding?? status in oil production for the Norwegian sector of North Sea.
Basic polycarboxylic and sulphonated polycarboxylic acid chemistries were used as the basis of the new scale-inhibiting products. The new inhibitors were developed by examination of their scale inhibiting properties relative to conventional polycarboxylates and-in conjunction with biodegradation testing-were optimized with regard to scale inhibition, biodegradability, and price. Characteristics of the chemistries are shown in Table 1.
With the increased biodegradability and excellent scale inhibition performance of these range of chemistries, oil and gas producers can control scale in operations while meeting environmental requirements required in the North Sea and other locations around the world.
Experimental Details
Regulatory Testing
The regulatory requirements for ecotoxicological testing for all chemicals used for offshore drilling in the North Sea are specified in the OSPAR guidelines for the North-East Atlantic. These regulations were implemented in 2001 and are intended to harmonize the mandatory control systems for offshore chemicals. The three categories of tests required by OSPAR are:Acute toxicityBioaccumulationSeawater biodegradation (persistence)
PPCA and DETPMP are two common commercial scale inhibitors used to control mineral scaling in the oil and gas industry. Normally, PPCA is regarded as a nucleation inhibitor and DETPMP as a growth inhibitor. In this paper, the effect of PPCA and DETPMP blends on the inhibition efficiency of calcium carbonate scale formation is presented.
In this paper, calcareous scale formation was studied both in the bulk solution and on the metal surface in supersaturated scale formation solutions, which represent typical waters encountered in oil and gas production. The effect of inhibitor blends on scale formation is studied. It shows that the inhibitor has a different inhibiting effect on precipitation in the bulk solution and deposit formed on the metal surface and reasons for this are discussed. It also demonstrates that bulk precipitation and surface deposition are two different processes and both processes should be studied to completely understand an industrial scaling system.
This paper presents the mechanism of scale formation by water in oil fields and suggests an accurate model capable of predicting scaling phenomena in Iranian Oilfield operations due to mixing of incompatible waters or change in thermodynamics, kinetics and hydrodynamic condition of systems. A new and reliable scale prediction model which can predict scaling tendency of common oilfield water deposits in water disposal wells, water-flooding systems and in surface equipment and facilities is developed and present. The development of the model is based on experimental data and empirical correlation, which perfectly match Iranian oil fields conditions. Furthermore the simultaneous deposition of oilfield scales and competition of various ions to form scale which is common phenomena in oil fields are reflected in the development of the model allowing the effect of each scale on the others to be taken into account. The new model has been applied to investigate the potential scale precipitation in Iranian oilfields, either in onshore or offshore fields where water injection is being performed for desalting units’ water disposal purpose or as a method of secondary recovery or reservoir pressure maintenance.
The formation of calcium naphthenate precipitates and emulsions during oil production is becoming an increasing problem to the oil industry. Naphthenic acids, R-CO2H, are present in many crude oils and the hydrophilic nature of the carboxylic acid group means that they congregate at the oil-water interface. As the pressure drops during production and carbon dioxide is lost from solution, the pH of the brine increases, which in turn leads to dissociation of the naphthenic acid (RCO2H –> RCO2–). The naphthenates can then act as natural surfactants leading either to stabilised emulsions or solid deposits following complexation with calcium cations present in the aqueous phase. The naphthenate deposits collect predominantly in oil / water separators and de-salters but can also deposit in the tubing and pipelines.
This study has looked at a variety of conditions to determine when certain carboxylic acids will form naphthenate deposits under idealised laboratory conditions. A range of naphthenic acids of different molecular structure were dissolved in an organic phase (toluene) and mixed with synthetic brines containing a range of calcium concentrations typical of oilfield production waters. These tests have determined that as the size of straight chain carboxylic acids increases so does the amount of naphthenate deposit. Increases in brine pH also increased the amount of deposit. However, the effects of changes in calcium concentration and molecular structure on the formation of naphthenate deposits were more difficult to quantify. The work assists in increasing our understanding of the factors controlling the precipitation of naphthenate solids under controlled conditions and forms the basis for future studies in real oilfield fluids.
Many of the fields that have been discovered recently in the West African deep-offshore will produce acidic crudes associated with gas containing a high concentration of CO2.
During the oil production process, a pH increase due to decompression and carbon dioxide degassing may generate surface-active naphthenates that can drastically stabilize emulsified water in crude oil. These may also combine with metal cations present in the reservoir water and form deposits. In all cases, production operations may be seriously disturbed.
The aim of the work conducted was to assess naphthenate and scale inhibition and the various factors that can affect its efficiency. In particular, we studied scale inhibitor interactions on naphthenate prevention.
This paper presents the results of studies on emulsion stability and naphthenate deposit formation, evaluated for various acidic crudes. As the pH increased, various behaviors were observed: progressive emulsion stabilization or abrupt transitions from unstable to stable emulsions. Naphthenate deposits formed in some cases even at low pH. Such a diversity of behaviors was explained in terms of differences in acid natures.
To prevent emulsion stability and naphthenate deposits, selected demulsifier and scale inhibitor additives were then tested. Several types of demulsifiers were found to be efficient at both emulsion-breaking and naphthenate deposit inhibition. In some cases, mixtures of demulsifiers and scale inhibitors produced very good results, highlighting a synergetic effect between the two additives. Unfortunately, the use of scale inhibitors generally increased the calcium content of the oil phase. Basically, the use of scale inhibitor with acidic crudes degrades the oil quality in terms of water cut and metal content.
In Deep Offshore Fields, the injection of chemicals demands the installation of expensive and complex systems.
When the Girassol and Dalia projects, on the Block 17 in Angola, were undertaken, the Operator decided to limit the number of liners for continuous injection to one.
Through this liner, a Scale and a Corrosion inhibitor will be injected at the bottom of the well. In the near future, when the water cut becomes relevant, a demulsifier could be also injected.
The liner can also be used occasionally, for the injection of methanol, in order to remove the hydrate plugs.
The paper presents the research and development undertaken to determine the different molecules (scale and corrosion inhibitors plus demulsifiers) and their compatibilities, as well as the compatibility with any other fluid that could come in contact with the additive.
The multifunctional chemical that has been especially formulated for this application, contains three different products dissolved in the same solvent, even if, generally, they are soluble in different fluids.
The advantage of such a solution is that the percentages of each of the three base compounds can be adapted to the production conditions and the evolution of the water cut, without affecting their stability.
The solution of the compatibility problems has represented a real challenge. The three active substances should not only be mutually compatible, but the product itself has to be compatible with other fluids likely to be injected through the liner. These would include methanol, used for the prevention of hydrates, or glycols, for the preservation of the liners during the shut-down periods.
The last major challenge was to obtain a stable blend presenting a very low viscosity, capable of being injected over long distances and at low temperatures with a minimum pressure drop.
Many of the fields that have been or will be discovered in the near future show signs of biodegradation of the crude oil. The result of such biodegradation is a decrease in the amount of the paraffins associated with the formation of naphthenic acids. Some of these crude oils may have a Total Acid Number (TAN) close to 5mg/g. When the reservoir fluid contains a significant amount of CO2, one can expect to find mixed scale of calcium carbonate and naphthenate. The aim of the work conducted was to assess the various factors which affect the formation of mixed scale.
We studied, in particular, the consequences arising from the formation of highly surface-active naphthenates which, depending on the nature of the cations in the formation water, can form stable emulsions, calcium naphthenate deposits or mixed scale of calcium carbonate and calcium naphthenate.
This paper presents the ways to prevent emulsions or deposits resulting from the formation of naphthenates. Chemical prevention is the most commonly used method but problems can sometimes be solved by modifying the way crude is processed. We will also describe an example of a modified process that we plan to use.
We describe a novel abrasive jet cleaning system for removing scale from production tubulars. By careful selection of abrasives we can remove the mineral growth without damage to the steel. We also describe a field test for the system where it ran back to back with mills, an impact hammer and water jetting tools.
The abrasive selection is a critical parameter in the performance of the system. Pure water jets will clean certain soft scales, although they tend to lift the growth off the tubular in large pieces which are not conducive to good hole cleaning. Some water jetting systems use acid to soften the scale, but this limits the applicability of the system. The use of sand as an abrasive is common for certain jetting applications, however this can damage the tubing of jewelery. We discuss the selection of the Sterling Beads to clean the scale without damaging the steel.
We also describe the first field test of the system, where it was run in a well to clean Aragonite scale from 2 3/8 in. tubing. Numerous milling and tools had been tried, but all had failed to clean the tubing, and most had been destroyed. As had other mechanical and water jetting systems. The new abrasive jetting system using Sterling Beads was run and cleaned the tubing at a high penetration rate with minimal damage to the plastic coating which had originally coated the production tubing and no damage to the steel itself.
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Scale formation in industrial systems is an important engineering problem that leads to decreased system efficiencies, increased frequency of chemical cleaning and an increased number of outages due to metal integrity failure. In order to minimize the formation of scale deposits, threshold scale inhibitor treatments are common practice in an industry. This paper describes synthesis, characterization and comparative evaluation of two low molecular weight maleic acid copolymers as potential calcite scale inhibitors. GPC, FT-IR and thermal analyzers were employed for molecular characterization; scale inhibition efficiency was studied through static jar test, dynamic tube block method, iron dispersing ability test and through electrochemical technique such as electrochemical impedance technique. SEM analysis demonstrated inhibited and un-inhibited crystal morphology. Complete scale inhibition was possible at a low dose of 20–25ppm throughout the test regime.
Previous work has demonstrated how and where the mixingof incompatible brines occurs in waterflooded reservoirs, and what the impact would be on scale prevention strategies in terms of timing and placement of squeeze treatments. This paper extends this work, by modelling the resulting in-situ depositionprocess. The location of maximum scale deposition and the resulting brine compositions at the production well are calculated for a range of sensitivities, including reservoir geometry (1D, 2D areal, 2D vertical, 3D), well geometry (location and orientation within field and with respect to other wells and the aquifer), and reaction rate (ranging from no precipitation to equilibrium).
In conventional systems with no aquifer, it is demonstrated that maximum scale deposition occurs in the immediate vicinity of the production wellbore, and therefore low produced cation concentrations indicate inadequate squeeze treatments. In systems where water injection is into the aquifer, low cation concentrations may also result from deposition deeper within the reservoir. Maximum scale dropout still occurs as the fluids approach the production well, but sufficiently far from the wellbore to be unaffected by squeeze treatments, or to have any major impact on productivity. The reaction rate is critical in determining the amount of scale deposition, but even under equilibrium conditions, sufficient concentrations of scaling ions are delivered to the production well to necessitate squeezing the well, although using lower volumes of inhibitor. Once cation concentrations have been reduced, it is predicted that they will never pick up again.
This paper also discusses some of the limitations of modelling such systems, which include the determination of the kinetic reaction rates, size of the mixing zone, and the impact on permeability. Although the thermodynamics are fairly well understood, the kinetics are much more difficult. The size of the mixing zone is affected by numerical dispersion, and computationally intensive techniques are required to overcome this problem. Previous experience shows that formation damage factors are very difficult to extrapolate from coreflood data because there is a great difference between the dimensions of the mixing zone in the reservoir and the core plug.
Introduction
Previously presented work has shown the effect of brine mixing under various flow conditions, both idealised1,2(1D, 2D vertical, 2D areal, 3D) and actual reservoir conditions3,4(Alba Reservoir, North Sea). For the majority of these calculations a conventional reservoir simulator has been used. The advantages of using a conventional simulator are that a large proportion of waterflooded reservoirs have a field model dataset already available, the addition of tracer tracking to model the propagation of the mixing zone is relatively straightforward to implement, and the results are easy to visualise. This technique is quite powerful for demonstrating the movement of the water front and also the mixing zone relative to the production wells. Even within a given field the behaviour may vary quite markedly, depending on the configuration of neighbouring wells and the reservoir geometry, as was shown in the Alba case3.
Predicting potential scaling problems can be difficult, and numerous saturation indices and computer algorithms have been developed to determine if, when, and where scaling will occur. The Langelier, Stiff-Davis, and the Oddo-Tomson saturation indices, all widely used in the oil field, are compared and contrasted relative to calcium carbonate scale. New saturation indices for barium, strontium, and calcium sulfate scale formation are introduced and discussed, along with an updated version of the Oddo-Tomson calcium carbonate index. An updated version of the CaCO3 saturation index is presented that includes correction terms for fugacity effects and changes in the solubility of CO2 in oil and gas wells as functions of temperature, pressure, water cut, and hydrocarbons present. The CaCO3 saturation index does not require a measured pH and can accommodate the presence of weak acids, such as H2S, and weak organic acids in the system. The sulfate scale prediction methods (for gypsum, hemihydrate, and anhydrite) are easy to use, reliable, and designed for field use by an operator who may be untrained in chemistry. The prediction methods can be applied to any production well where calcium carbonate, calcium sulfate, strontium sulfate, or barium sulfate scale occurs.
The use of water-in-oil emulsions (w/o) to deploy scale inhibitors has been reported in the literature as an alternative to water-based squeeze treatments. The non-aqueous nature of these emulsions has the advantage to prevent water blocking, which adversely affects oil production in aqueous squeeze treatments. Placing the scale inhibitor in a w/o or "invert" emulsion has shown in some cases the additional advantage of enhancing treatment lifetime. However, results from the literature seem contradictory and highlight a poor understanding of this technology.
The present paper aims at providing further insight on emulsified scale inhibitor placement in porous media. Preliminary experiments, using a low molecular-weight biopolymer as scale inhibitor, showed low adsorption/retention in aqueous solution. Re-formulation of the product under invert emulsion was investigated to enhance inhibitor retention.
Results from coreflood experiments, in well-characterized silicon carbide (SiC) packs provided preliminary evidence of aqueous droplet adsorption as the main retention mechanism in porous media. This was expected considering the average droplet size of 0.3 μm. The mother formulation of the w/o emulsion is a concentrate, containing 80% weight of water phase and 8% weight of active scale inhibitor. It can be diluted down to 2% water phase adding the desired oil phase without loosing stability or increasing the droplet size.
These results are a promising first step towards the development of a technically and commercially viable, environment-friendly scale inhibitor technology based on w/o emulsions.
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
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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?
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