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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.
... However, the design, size, and geometry of smart completion tools can impact the prevention of scaling deposition. Thus, there is a need to investigate operating conditions and equipment designs that can influence the formation and deposition of precipitates within the oil production process (Lai et al., 2020;Olajire, 2015). ...
... The development and accumulation of calcium carbonate precipitates are influenced by many factors, including supersaturation, temperature, pH, calcium and bicarbonate/carbonate ratio, CO2 pressure, equipment geometry, flow rate, and the presence of external ions (Blue et al., 2017;Eroini et al., 2013;Lai et al., 2020;Olajire, 2015;Zhang et al., 2018). Moreover, the formation of metastable forms as intermediates in the transition to more stable forms hinges on these factors, particularly the water content (Donnet;Bowen;Lemaître, 2009;Du;Amstad, 2019). ...
... From thermodynamic calculations, the model provides the mass of calcium carbonate required for the system to reach a new state of chemical equilibrium. This represents the maximum amount of calcium carbonate that the system can produce under given conditions (Cosmo et al., 2019;Haarberg et al., 1992;Olajire, 2015). On the other hand, the kinetic model output provides the mass of calcium carbonate that the system can produce during the residence time, introducing the development of kinetic rates over time and supersaturation (Lassin et al., 2018;Rodriguez-Blanco et al., 2011;Zhang et al., 2018). ...
The formation and deposition of inorganic salts on industrial equipment surfaces pose significant financial and technological challenges for various industries, particularly the oil industry, because of the transportation of multiphase fluids, such as water, oil, and gas, under high temperature, pressure, and salinity conditions (Crabtree et al., 1999; Kamal et al., 2018). Calcium carbonate scaling presents a particular challenge for scale control, as it is sensitive to pressure and temperature variations (Blue et al., 2017; Cosmo, 2013a; Du & Amstad, 2019). Smart completions are a favored method for production control and scale surveillance, as they enable the reduction of water production or the mixing of incompatible water chemistries (Bouamra et al., 2020; Santos et al., 2017). However, the design, size, and geometry of smart completion tools can impact the prevention of scaling deposition. Thus, there is a need to investigate operating conditions and equipment designs that can influence the formation and deposition of precipitates within the oil production process (Lai et al., 2020; Olajire, 2015).
A mathematical methodology has been developed to predict precipitation rates along the oil and gas workflow within these smart completions. This involves a comprehensive simulation of the particles, characterizing the kinetic, thermodynamic, and fluid-dynamic aspects of CaCO3 produced within the fluids in the oil and gas industry. Such a simulation can serve as a virtual sensor for potential analysis, control, and monitoring of incrustation problems, offering a more complete tool than the purely thermodynamic simulations typically used for prediction by the oil and gas industry (Bouamra et al., 2020; Lassin et al., 2018; Neubauer et al., 2022; Sanni et al., 2015).
The proposed methodology integrates calcium carbonate thermodynamics, kinetics, and flow dynamics along the production flow to assess the risk of CaCO3 precipitation. The simulation workflow combines a polymorphic population model to define the CaCO3 risk index based on particle kinetics, a multiphase thermodynamic model to simulate supersaturation conditions, and computational fluid dynamics to produce pressure and fluid flow profiles along the equipment. By combining these three models, kinetic and thermodynamic precipitation rates are calculated to obtain a comprehensive CaCO3 risk index. This work introduces one of the first approaches to characterizing the calcium carbonate risk index along the oil production process by incorporating both fluid dynamics and population modeling. The presented methodology offers a robust alternative for evaluating the criticality of various equipment designs and operating conditions within the oil industry. In addition to the conventional thermodynamic approach, this work will explore different methods to calculate the index using integrated thermodynamic, kinetic, and flow information.
... Hydrophilic organic or inorganic inhibitors work best. Though toxic and expensive, they can manage oilfield scales in production conduits and completion systems (Olajire 2015). Most conventional polymer-based SIs remain in the environment for years after disposal. ...
... In summary, it was observed that in contrast to CaSO 4 scale inhibition which requires low temperatures, increased temperatures have a negligible effect on the inhibition of CaCO 3 and BaSO 4 scales. This aligns with studies that indicate elevated temperatures enhance the growth of CaCO 3 and BaSO 4 scales, thus requiring increased inhibitor concentration for better efficiency (Dyer and Graham 2002;Olajire 2015;Al-Sabagh et al. 2018;Zhao et al. 2019). However, optimum IE was observed at 71 � C for BaSO 4 and CaSO 4 scales at 100 ppm and 80 ppm, and at 90 � C and 80 ppm for CaCO 3 scales. ...
... Contrary to CaSO 4 scale, which requires lower temperature, CaCO 3 , and BaSO 4 scales require high temperatures and inhibitor concentrations for effective inhibition. Based on literature findings, increasing inhibitor concentration is required for improved efficiency since higher temperatures promote the development of CaSO 4 and BaSO 4 scales (Dyer and Graham 2002;Olajire 2015;Al-Sabagh et al. 2018). In conclusion, the performance of the formulated SIs compared favorably with CSI and, as a result, they have the potential for consideration as inexpensive, eco-friendly, and effective green oilfield SIs. ...
Scale deposition occurs due to changes during injection operations and the mixing of incompatible brines. Scale inhibitors are used to mitigate such occurrences. The inhibition efficiency of the glutaraldehyde-ROSE resin (ROG) was evaluated in synthetic brines containing CaSO 4 , BaSO 4 , and CaCO 3 under static conditions according to NACE standard methods. The formulated scale inhibitor was compatible with the brine and thermally stable. The inhibition studies of ROG revealed optimal inhibition of 89% at 80 ppm and 58% at 100 ppm at 90 � C and 22 h, respectively, for BaSO 4 and CaCO 3 scales, while for CaSO 4 scales, optimal inhibition of 67% was observed at 100 ppm, 71 � C, and 22 h. On comparison, the Commercial Scale Inhibitor (CSI) showed optimal inhibition of 97% at 100 ppm and 94% at 80 ppm at 71 � C and 22 h, respectively, for BaSO 4 and CaSO 4 scales, while for CaCO 3 scales, optimal inhibition of 98% was observed at 80 ppm, 90 � C, and 22 h, respectively. This indicates that ROG efficiently mitigated the formation of CaSO 4 , BaSO 4 , and to some reasonable extent, CaCO 3 scales, and its inhibition performance compared favorably with the CSI, thus unveiling its potential for consideration as a green oilfield scale inhibitor.
... The formation and deposition of calcium carbonate precipitates are known to be influenced by various factors, including supersaturation, temperature, pH, calcium and bicarbonate/carbonate ratio, CO2 pressure, and the presence of external ions (Blue et al., 2017;Cosmo, 2013;Haarberg et al., 1992;Olajire, 2015). Additionally, the formation of metastable forms as intermediates in the formation of a more stable form is also dependent on these factors, especially the water content (Donnet et al., 2009;Du & Amstad, 2019). ...
... M. Neubauer, 2022;Sanni et al., 2022). While the tool for calculating supersaturation has been extensively studied and validated for these conditions, the same is untrue for the calcium carbonate populational kinetics (Du & Amstad, 2019;Gebauer et al., 2018;Olajire, 2015). However, it is important to notice that the difficulty in obtaining data from systems with high temperature, pressure, and salinity is a major limitation to the quality of both thermodynamic and kinetic parameters (Gebauer et al., 2018;Kawano et al., 2009;Van Driessche et al., 2017). ...
... However, it is important to notice that the difficulty in obtaining data from systems with high temperature, pressure, and salinity is a major limitation to the quality of both thermodynamic and kinetic parameters (Gebauer et al., 2018;Kawano et al., 2009;Van Driessche et al., 2017). Despite these challenges, researchers have shown great interest and effort in continually developing tools that can provide a different approach or conclusion to this topic (Du & Amstad, 2019;Kamal et al., 2018;Mayorga et al., 2019;Olajire, 2015). In this work, a novel approach involving fluid dynamic, thermodynamics and kinetics is presented to evaluate the calcium carbonate precipitation potential in a an open-hole completion assembled with a perforated liner. ...
... The formation and deposition of calcium carbonate precipitates are known to be influenced by various factors, including supersaturation, temperature, pH, calcium and bicarbonate/carbonate ratio, CO2 pressure, and the presence of external ions (Blue et al., 2017;Cosmo, 2013;Haarberg et al., 1992;Olajire, 2015). Additionally, the formation of metastable forms as intermediates in the formation of a more stable form is also dependent on these factors, especially the water content (Donnet et al., 2009;Du & Amstad, 2019). ...
... M. Neubauer, 2022;Sanni et al., 2022). While the tool for calculating supersaturation has been extensively studied and validated for these conditions, the same cannot be said for the calcium carbonate populational kinetics (Du & Amstad, 2019;Gebauer et al., 2018;Olajire, 2015). However, it is important to notice that the difficulty in obtaining data from systems with high temperature, pressure, and salinity is a major limitation to the quality of both thermodynamic and kinetic parameters (Gebauer et al., 2018;Kawano et al., 2009;Van Driessche et al., 2017). ...
... However, it is important to notice that the difficulty in obtaining data from systems with high temperature, pressure, and salinity is a major limitation to the quality of both thermodynamic and kinetic parameters (Gebauer et al., 2018;Kawano et al., 2009;Van Driessche et al., 2017). Despite these challenges, researchers have shown great interest and effort in continually developing tools that can provide a different approach or conclusion to this topic (Du & Amstad, 2019;Kamal et al., 2018;Mayorga et al., 2019;Olajire, 2015) Therefore, the development of a reliable thermodynamic and kinetic model for prediction of CaCO3 precipitation rate, allowing the further study of the relationship between the calcium carbonate precipitation and surface deposition, under oil and gas production conditions can add to the current knowledge and serve as a valuable tool for studying these phenomena in an interconnected manner (Bouamra et al., 2020;Molnár et al., 2023;Sanni et al., 2022). In this wok, a novel methodology involving the coupling of fluid dynamics, thermodynamics and kinetics is presented to assess the calcium carbonate precipitation potential in an open-hole completion assembled with a perforated liner. ...
The formation and deposition of inorganic salts on industrial equipment surfaces pose significant financial and technological challenges for various industries, particularly the oil industry, due to the transportation of multiphase fluids such as water, oil, and gas under high temperature, pressure, and salinity. (Crabtree, M., Eslinger, D., Fletcher, P., Miller, M., Johnson, A., King, 1999; Kamal et al., 2018a). These conditions can bring significant challenges in scale control, especially for calcium carbonate scaling, which is a scale type that can be vulnerable to pressure and temperature variations (Blue et al., 2017; Cosmo, 2013a; Du & Amstad, 2019). To ensure optimal scale control and surveillance, smart completions have emerged as one of the most favorable approaches in the oil and gas industry. These completions offer real-time and selective zone control in oil and gas wells, minimizing unwanted water production and maximizing oil and gas production. They allow operators to isolate or produce specific zones, controlling or preventing mixing of incompatible water chemistries. Additionally, smart completions provide water shutoff capabilities, allowing operators to remotely control valves and downhole tools to shut off water-producing zones. This feature significantly reduces the undesirable production of water, commonly encountered during oil or gas production in mature reservoirs (Bouamra et al., 2020; H. F. L. L. Santos et al., 2017). However, the design, size, and geometry of the smart completion tool can impact the prevention of scaling deposition. As a result, there is a need to investigate operating conditions and equipment design that can promote the formation and deposition of precipitates within the oil production process (Kamal et al., 2018a; Sanni et al., 2022). To address this issue, a novel mathematical methodology has been developed to predict precipitation rates along the oil and gas workflow within these smart completions. A complete simulation of the particles, characterizing the kinetic, thermodynamic, and fluid-dynamic aspects of the CaCO3 produced within the fluids produced in the oil and gas industry, could be used as a virtual sensor for potential analysis, control and monitoring of incrustation problems, offering a more complete tool than the pure thermodynamic simulations that are usually used as prediction tools by the oil and gas industry (Bouamra et al., 2020; Lassin et al., 2018; T. Neubauer et al., 2022; Sanni et al., 2015). The proposed methodology involves the use of calcium carbonate thermodynamics, kinetics, and flow dynamics along the production flow to assess the risk of CaCO3 precipitation. The simulation workflow combines a polymorphic population model to define the CaCO3 particle kinetics, a multiphase thermodynamic model to simulate supersaturation conditions, and computational fluid dynamics to produce the pressure and fluid flow profiles along the equipment. The combined simulation of the three models produces kinetic and thermodynamic precipitation rates that are used to obtain a CaCO3 risk index. This work describes the model calculations to assess calcium carbonate formation in an open-hole completion assembled with a perforated liner composed of multiple tiny, drilled holes along the production tubing.
... However, an increase in scale inhibition performance from 52.86 % to 58.82 % at 100 ppm was observed for CaCO3 scales as the evaluation temperature increased from 71 o C to 90 o C (Fig. 6a). This aligns with studies that indicate elevated temperatures enhance the growth of CaCO3 scales, thus requiring increased inhibitor concentration for better efficiency [12,[23][24][25]. ...
... The scale-inhibiting potential of a potential green oilfield scale inhibitor derivatized via chemical modification of red onion skin extract (ROSE) [12,17,23,24,26]. In conclusion, the performance of the formulated SIs, though slightly lower across the concentration range studied for CaCO3 and CaSO4 scales, compared favorably with CSI in terms of their ability to inhibit and, as a result, reveal they can be considered potentially inexpensive, renewable, eco-friendly, and effective green oilfield scale inhibitor alternatives for CaSO4 scales. ...
Oilfield-scale formation is a persistent challenge in the oil industry. While numerous scale inhibitors have been in use for decades, there is a significant research gap in discovering renewable, cost-effective, ecologically friendly, and efficient inhibitors. This study sets out to fill this gap by investigating the potential of scale inhibitors (SIs) made from bio-resin derivatives of red onion skin; ROF and ROFU, in reducing CaCO3 and CaSO4 scales. The scale inhibition performance of ROF and ROFU was rigorously evaluated using the NACE standard static bottle test method. The data revealed that increasing scale-inhibitor contact time, concentration, and temperature enhances inhibitor efficacy, with the best inhibition efficiencies found for ROF and ROFU on the CaSO4 scale compared to the CaCO3 scale across all studied parameters. A comparison of the prepared SIs with a commercial scale inhibitor (CSI) showed a high inhibition rate of over 90% at minimal dosage of 60ppm in both scales studied. Despite having a lower inhibition rate (IE) than CSI, ROF and ROFU demonstrate significant potential as green oilfield SIs. This sustainable technique, which transforms agro-waste into a valuable oilfield chemical via a one-pot chemical process, could have profound economic and societal benefits, offering hope for a more sustainable future in the oil industry.
... Scale formation along valves, pipelines, and pumps in the oil and gas industry is caused by the interaction between saline formation and injection waters [1][2][3][4]. These media lead to the generation of low-solubility carbonate and sulfate salts of cations such as Ca 2+ , Sr 2+ , and Ba 2+ . ...
... (D) Extraction efficiency evaluation in terms of κ w (1) and Ca 2+ content from extracted water and directly from four oils (2). The κ w data were recorded at the ideal conditions as cited above with BPA and 3D-printed devices with 1 (3D1), 3 (3D3), and 5 (3D5) mixing channels (1). To obtain the Ca 2+ contents, we used the 3D5 device (2). ...
Flow assurance plays an important role in designing safe and efficient operation techniques along oil and gas explorations. In this way, approaches able to provide fast and field-deployable monitoring of scaling ions in crude oils may benefit the petrochemical industry in its long-standing mission to devise ideal flow conditions by aiding the adoption of optimum dosages of off-the-shelf products. We first describe a scalable platform toward rapid (∼10 min) determination of multiple scaling ions in crude oils. Our platform is based on turbulence-mediated ultrafast and efficient microfluidic solvent extraction (μSE) combined with impedimetric sensors and machine learning to determine different ions from a single impedance plot. 3D-printed μSE devices were able to afford ultra-fast (residence time of ∼1.0 s) extractions. Nanocellulose-based foams allowed us for rapidly separating the water-oil phases, with the aqueous phase being sampled for posterior detection. Scalable sensors obtained by distinct prototyping methods provided the multidetermination of ions in 50 produced water samples (Mg2+, Ca2+, Sr2+, and Cl⁻) and 49 crude oils (Ca2+ and Cl⁻). The accuracies ranged from ∼96 to 100%. Importantly, ML models trained on standard solutions delivered poor accuracy, showing the relevance of learning supervised algorithms with real samples to deliver accurate capacitive analyses.
... 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.
... They can carefully design mining plans based on the microstructure characteristics of the reservoir to maximize recovery, reduce mining costs, and minimize adverse effects on groundwater and the environment. This microscale research method provides strong support for technological innovation and sustainable development in the field of oil and gas exploration and extraction (Abrams, 2020;Buddo et al., 2022;Li et al., 2022;Lv et al., 2023;Olajire, 2015;Xi et al. 2016). ...
Oil and gas resources serve as the driving force for economic and social development. This rapid development of science and technology has accelerated the exploration, development, and utilization of oil and gas resources, and thus led to spurts in related research. However, the research trends in global oil and gas exploration vary with the progress of science and technology as well as social demands. Accordingly, they are not easily captured. This study explores the research trends in global oil and gas exploration through the bibliometric analysis of 3460 articles on oil and gas exploration collected from the Web of Science database and published from 2013 to 2023. The research hotspots, objects, regional distribution, methods, and evaluation methods in oil and gas exploration are analyzed, and the direction of development of oil and gas exploration is presented on this basis. The research characteristics of four major countries or regions related to oil and gas exploration were further investigated and compared. The results show that the number of publications on oil and gas exploration research has been continuously increasing in the past decade, with China ranking the top in terms of publications. Given the continuously evolving global energy demand, exploration of unconventional oil and gas, application of digital technology, deep and emerging regional resource exploration, and environmentally friendly and low‐carbon source exploration will be future research hotspots.
... With the development of oilfields, the comprehensive water cut continues to rise, and factors such as incompatibility between formation water and injected water lead to a large amount of scaling in gathering pipelines and stations. Scaling prevention and control in oilfields has become one of the main challenges in oilfield development and production [1]. Scaling in oilfield gathering and transportation stations is mainly concentrated in the main control valves, the inlet and outlet pipelines of the heater, and the heater coils, etc., with severe scaling in multi-layer mixed transportation and oil wells where injection water is seen at the station. ...
Scaling is a significant challenge in oilfield production gathering and transportation stations, and it not only constrains the economic efficiency but also affects the development of oil and natural gas. This study proposes a scaling prediction model based on chemical experimental analysis and reservoir dynamic analysis methods for the gathering and transportation stations in the Changqing Oilfield. The objective of this study is to provide technical support for the oilfield to advance precise management and achieve cost reduction and efficiency enhancement. Initially, the water quality and scale samples of the oilfield were tested and analyzed using Inductively Coupled Plasma (ICP), Ion Chromatography (IC), and Scanning Electron Microscopy-Energy Dispersive Spectroscopy (SEM-EDS), and the distribution and patterns of scaling in the gathering and transportation pipelines were studied. Based on this, using the test data and the production liquid ratio of each development layer at the gathering and transportation stations, a reservoir dynamic correlation method was employed to construct a prediction model for the development layer with the highest similarity to the tested water samples at the stations and the types of scale samples. The results indicate that this prediction method can effectively reduce the scaling rate and provide guidance for the anti-scaling process in the Changqing Oilfield.
... Oilfield scales inhibitors: The unsolicited aggregation of different materials within the main working parts in an oil or gas production system, commonly referred to as scale deposition, is a major issue in the industry of energy commodities. Typically, oilfield scales contain calcium carbonates and sulfates, including barium sulfate and iron sulfides, among which calcium carbonate (CaCO 3 ) is one of the main components [156][157][158]. In [159], the authors employ DFT and ab initio molecular dynamics (AIMD) techniques to study the performance of scales inhibitors, such as polyacrylamide (PAM) and its silica functionalized counterpart (PAM-Silica). ...
We start presenting an overview on recent applications of linear polymers and networks in condensed matter physics, chemistry and biology by briefly discussing selected papers (published within 2022–2024) in some detail. They are organized into three main subsections: polymers in physics (further subdivided into simulations of coarse-grained models and structural properties of materials), chemistry (quantum mechanical calculations, environmental issues and rheological properties of viscoelastic composites) and biology (macromolecules, proteins and biomedical applications). The core of the work is devoted to a review of theoretical aspects of linear polymers, with emphasis on self-avoiding walk (SAW) chains, in regular lattices and in both deterministic and random fractal structures. Values of critical exponents describing the structure of SAWs in different environments are updated whenever available. The case of random fractal structures is modeled by percolation clusters at criticality, and the issue of multifractality, which is typical of these complex systems, is illustrated. Applications of these models are suggested, and references to known results in the literature are provided. A detailed discussion of the reptation method and its many interesting applications are provided. The problem of protein folding and protein evolution are also considered, and the key issues and open questions are highlighted. We include an experimental section on polymers which introduces the most relevant aspects of linear polymers relevant to this work. The last two sections are dedicated to applications, one in materials science, such as fractal features of plasma-treated polymeric materials surfaces and the growth of polymer thin films, and a second one in biology, by considering among others long linear polymers, such as DNA, confined within a finite domain.
... During the development process, the rapid water intrusion of injected water or formation water along the fracture channel can occupy the space that would otherwise be available for the flow of oil and gas fluids [9,10] to increase the resistance of the gas flow [11,12], which can remain in the reservoir and form stagnant water [13]. At the same time, the retention of water in fractured reservoirs varies due to factors such as pressure, temperature, and flow velocity [14]. The dissolved minerals in the water may reach a supersaturated state and precipitate, and problems such as blockage and scaling affect the productivity and economic efficiency of the gas reservoir [15][16][17][18][19]. ...
In this paper, well Keshen 221 was taken as the research object. The stagnant water–rock static experiment showed that, after 8 weeks of the residual water–rock static reaction, the pore size of the inner profile of the rock slice increased from 5 μm to 90 μm, and calcium carbonate crystals were deposited in the hole. Combined with the microscopic visualization model, it is observed that the reservoir blockage mostly occurs at the pore throat diameter, and the small fracture (30 μm) is blocked first, then the large fracture (50 μm). So, it is inferred that the blockage of the reservoir flow channel is caused by the migration of the crystals precipitated by the interaction between the stagnant water and the reservoir rock. On this basis, the TOUGHREACT reservoir model was further constructed to simulate the scaling of the stagnant water in the reservoir matrix and used to compare the scaling of the fractures with 7% and 30% porosity and the retained water at 0.658 m and 768 m. The pre-results of reservoir scaling show that the scaling is more serious when the fractures occur in the far well zone than when the fractures occur in the well entry zone. At the same location, the deposition of large fractures is six times that of small fractures, and the scaling is more severe in large fractures.
... Formation of mineral scales in flowlines and equipment is a major challenge faced by industries such as power plants and oil and gas production systems. Carbonates and sulfates of calcium typically deposit as scale in the wells, flowlines, and surface facilities, leading to restricted flow, increased pressure drops, and blockage in the oil field (Olajire 2015, Li et al. 2017. It can also lead to under-deposit corrosion and loss of metal. ...
Mineral scales of calcite are common in the oil field and pose a serious integrity problem in the wellbore, flow lines, and equipment. It is also a challenge faced by industries such as refineries and power plants. Scale deposition is a complex process depending on various factors such as concentration of scaling species, temperature, pH, and flow rates. Deterministic models are used to predict the scale formation from the level of supersaturation of the scaling species in the water at the operating conditions. However, due to the complexity of the interaction of variables affecting the scaling and inhibition by chemicals, it is suitable to be represented by statistical models. This work focused on applying statistical analysis techniques such as response surface methodology to understand the effect of different operating parameters on the inhibition efficiency of maleic acid-acrylamide copolymer on CaCO3 scales. The copolymer was synthesized, and its inhibition efficiency on the calcite scale was tested using static jar tests at different pH, temperature, and inhibitor concentrations. The effect of the critical parameters on the inhibition efficiency was analyzed using the statistical technique of Response Surface Methodology (RSM). The design of experiments (DoE) was created using a Box–Behnken design with three levels for each factor. The linear and the quadratic effects of the factors were studied and the interaction effects were analyzed using analyses of variance (ANOVA) and RSM. A desirability function was used to optimize the performance for the combination of the variables. The analysis showed that the linear effect of the parameters had the highest impact on the inhibition efficiency. Significant interaction effects were also identified between the operating variables. A transfer function was used to model the experimental data of inhibitor performance.
... Oilfield solid scale accumulation in petroleum pipelines, which generates flow control issues while transferring crude oil and natural gas, has agained a research focus [1]. Scale formation in oil and gas pipeline networks creates the conditions for various possible disasters. ...
... In practice, the adoption of insufficient MICs causes the stopping of oil production due to early pipeline blockage. 36 Conversely, it is worth underlining that the strategy based on overdosing antiscale products can increase the scale formation, as observed here ( Figure S12) owing to the incompatibility between the water composition and input (i.e., Product C at concentrations higher than 90 ppm). In this regard, providing an optimum MIC is of paramount significance to prevent pipeline blockages that are critically detrimental to the entire supply chain of related inputs and products to society. ...
Flow assurance is a long-term challenge for oil and gas exploration as it plays a key role in designing safe and efficient operation techniques to ensure the uninterrupted transport of reservoir fluids. In this regard, the sensitive monitoring of the scale formation process is important by providing an accurate assessment of the minimum inhibitor concentration (MIC) of antiscale products. The optimum dosage of antiscale inputs is of pivotal relevance as their application at concentrations both lower and higher than MIC can imply pipeline blockages, critically hindering the entire supply chain of oil-related inputs and products to society. Using a simple and low-cost impedimetric platform, we here address the monitoring of the scale formation on stainless-steel capillaries from its early stages under real topside (ambient pressure and 60 °C) and subsea (1000 psi and 80 °C) sceneries of the oil industry. The method could continuously gauge the scale formation with a sensitivity higher than the conventional approach, i.e., the tube blocking test (TBT), which proved to be mandatory for avoiding misleading inferences on the MIC. In fact, whereas our sensor could entail accurate MICs, as confirmed by scanning electron microscopy, TBT suffered from negative deviations, with the predicted MICs being lower than the real values. Importantly, the impedance measurements were performed through a hand-held, user-friendly workstation. In this way, our method is envisioned to deliver an attractive and readily deployable platform to combat the scale formation issues because it can continuously monitor the salt precipitation from its early stages and yield the accurate determination of MIC.
... In fact, they are primarily used to inhibit carbonate, sulfate, and phosphate scales [9,10]. Besides that, the inherent biodegradability of phosphonates were reported to be less than 40% in 28 days, while phosphino-polyacrylates were reported as non-biodegradable [11]. ...
Chemical flooding is regarded as a promising enhanced oil recovery technique to recover more hydrocarbon from reservoirs. However, the dissolution of quartz minerals in a highly alkaline environment poses the risk of silicate scaling near the production well region from the mixing of two different waters. Commercial scale inhibitors are effective, but they are also harmful to the environment. This paper aims to provide insights into current advances in environment-friendly or “green” scale inhibitors for petroleum upstream. Previous research works have demonstrated that green chemicals are effective in mitigating silicate, carbonate, and sulfide scales. Polyamidoamine or amide-based inhibitors have been widely investigated in recent literature due to several advantages. The addition of anionic compounds in these inhibitors enhanced scale inhibition efficiency by roughly 10%. Nevertheless, the reported findings were deliberated for industrial wastewater treatment. Meanwhile, understanding the performance of polyamidoamine or amide-based scale inhibitors in petroleum upstream is inadequate to a certain extent. The formation process of silicate scales inside a reservoir is rather complicated by looking at the influence of water salinity, composition of brine, temperature, pressure, and rock type. Hence, it is essential to study and develop green scale inhibitors that are effective and environmentally friendly to meet increasingly stringent disposal regulations in the petroleum industry. ABSTRAK: Pembanjiran kimia merupakan teknik pemulihan minyak. Ia berpotensi dalam memperoleh lebih banyak hidrokarbon dari takungan. Namun, pelarut mineral kuarza dalam persekitaran beralkali tinggi memberi risiko penumpukan silikat berhampiran kawasan takungan pengeluaran. Ia disebabkan oleh pencampuran dua jenis cecair berbeza. Perencat penumpukan silikat komersial adalah berkesan, tetapi sangat berbahaya pada alam sekitar. Kajian ini bertujuan bagi menambahbaik kemajuan perencat silikat mesra alam terkini atau perencat silikat hijau bagi bidang saliran petroleum. Kajian terdahulu telah membuktikan bahawa bahan kimia mesra alam adalah berkesan dalam pengurangan penumpukan silikat, karbonat dan sulfida. Perencat poliamidoamina atau perencat bersumber amida telah dikaji secara meluas dalam beberapa kajian sejak kebelakangan ini kerana kelebihannya yang banyak. Penambahan sebatian anionik dalam perencat ini mampu meningkatkan keberkesanan perencat silikat sebanyak 10%. Namun, laporan kajian terdahulu adalah khusus bagi rawatan sisa air industri. Sementara itu, pemahaman tentang prestasi perencat silikat bersumberkan poliamidoamina atau perencat bersumber amida dalam saliran petroleum masih tidak mencukupi. Proses pembentukan penumpukan silikat dalam takungan adalah agak rumit berdasarkan faktor saliniti air, komposisi air garam, suhu, tekanan dan jenis batuan. Oleh itu, kajian dan pembangunan berkesan tentang perencat silikat mesra alam adalah penting bagi memenuhi peraturan pelupusan sisa yang semakin ketat dalam industri petroleum.
... This causes oversaturation of scale components in the produced water due to mineral precipitation. Seawater, with its high sulfate ion concentration, combines with formation water high in calcium and barium ions, leading to the precipitation of sulfate scales such as barium sulfate and calcium sulfate [6,5]. Amiri and Moghadasi [7] in their study stated that calcium carbonate scales found in oilfield operations are formed from the combination of calcium and bicarbonate ions. ...
This preliminary study explores the potential of cashew gum as a sustainable, effective inhibitor of calcium carbonate scale by characterization analysis to determine its composition, temperature-tolerance and crystallinity in relation to conventional scale inhibitors. The use of green materials has garnered attention as a promising natural compound for industrial processes. Scale formation, a pervasive issue in oil production leads to reduced efficiency and increased maintenance costs caused by blockages in pipelines etc. However, scale inhibitors have been used to control various scale types. Cashew gum, a natural polysaccharide, with its biodegradable and eco-friendly characteristics aligns with global emphasis on sustainable, green chemistry. The preliminary analysis of the scale-inhibitory effect of cashew gum was evaluated using Thermogravimetric analysis (TGA), X-ray diffraction (XRD), Fourier-transform-infrared spectroscopy (FTIR), and Gas chromatography-mass spectrometry (GC-MS) to analyze their crystal structure, thermal stability, identify and quantify the chemical compounds. Results showed an onset degradation at 327.3 ˚C 211 temperature with a 29% decline in mass of the sample and a calcination temperature of 525 ˚C. The XRD showed a single peak at 19.20˚indicating poor crystallinity of the extract, thus a mixture of crystalline and amorphous phases was proposed. The FTIR spectra showed a symmetrical stretching vibration of the O-H bond, characteristic of glucoside ring. The presence of CO bonds and carbonyl moiety was observed at several low peak intensities indicating a low composition of these functional groups. The chromatogram identified six compounds linked to a functional group with 7-octadecenoic acid methyl ester having the highest peak area of 63.52 %, indicating that fatty acids are the dominant constituents in cashew gum. Its compatibility with diverse water compositions makes it a potential solution for scale inhibition. The study shows that cashew gum is a viable, eco-conscious option for mitigating scales based on its chemical composition and thermal stability.
... As a result, it becomes essential to employ anti-scaling measures to ensure the preservation and effectiveness of oil and gas production systems. Earlier methods such as chemical inhibitors, dissolvers, and mechanical treatments have demonstrated partial effectiveness in combating scaling [33,35,36]. However, these methods often encounter disadvantages such as exorbitant expenses, limited efficiency, and environmental apprehensions. ...
As the oil and gas industry continues to evolve, the utilization of advanced materials becomes crucial for maximizing efficiency and productivity. Nanoemulsions (NEs) have emerged as a promising solution for various downhole applications. Their unique properties, enhanced stability, and improved performance have led to applications in enhanced oil recovery, drilling fluids, fracturing fluids, and produced water treatment. However, while NEs offer significant advantages, production costs, stability during transportation and storage, as well as scale-up challenges must be carefully considered. This chapter aims to provide an overview of NEs for oil and gas applications, discussing the current benchmark, potential implementation, properties, and various applications. Furthermore, it will provide recommendations and insights on how to effectively implement NEs in the field. It is important to recognize that the ongoing research and development efforts hold the potential to further revolutionize the oil and gas applications and contribute to a more sustainable processes and operations.
... (1) (2) The presence of other constituents in the formation water, such as alkaline earth ions (like barium and strontium, Ba 2+ and Sr 2+ , respectively), bicarbonate (HCO 3 -) and sulfate (SO 4 2-) ions, and suspended solids, will be reported as they can contribute, directly or indirectly, to the formation of deposits. ...
Hydrogen sulfide (H2S) and carbon dioxide (CO2) present in oil and natural gas cause mild steel corrosion, potentially resulting in formation of corrosion product layers on the internal surfaces of tubulars. In field experiences relating to the research reported herein, this has led to restrictions on the flow of water produced from a three-phase horizontal separator. This paper demonstrates a specific case of chemical removal of relatively hard, dark, and adherent heterogeneous deposits on the internal surface of the pipe. The phases involved in this process are iron sulfide, iron oxides and calcium carbonate existing as scales/corrosion products. To evaluate their dissolution, laboratory tests were conducted using hydrochloric acid (HCl) with additions of chlorine in the form of calcium hypochlorite [Ca(ClO)2]. Appropriate safety measures were taken employed, considering hazards associated with chlorine and toxicity of hydrogen sulfide. The treatment regime had 87 % effectiveness for scale removal in combination with propargyl alcohol (2-propyn-1-ol) as a corrosion inhibitor.
... Scaling combines elements of both of these systems. 90 In contrast to bulk crystallization, which is the outcome of homogeneous nucleation mechanisms, surface crystallization is the consequence of a variety of different types of nucleation. The different stages of scale formation are described as follows: 91 • Aggregation Ion pairs are formed when cations and anions in a solution, such as Ca 2+ and CO 3 2− or SO 4 2− , collide and reach supersaturation levels. ...
Hydraulic fracturing uses a large amount of fresh water for its operation; conventional wells can consume up to 200 000 gallons of water, while unconventional wells could consume up to 16 million gallons. However, the world’s fresh water supply is rapidly depleting, making this a critical and growing problem. Freshwater shortages during large-scale hydraulic fracturing in regions that lack water, such as the Arabian Peninsula and offshore operations, need to be addressed. One of the ways to address this problem is to substitute fresh water with seawater, which is a sustainable, cheap, and technically sufficient fluid that can be utilized as a fracturing fluid. However, its high salinity caused by the multitude of ions in it could induce several problems, such as scaling and precipitation. This, in turn, could potentially affect the viscosity and rheology of the fluid. There are a variety of additives that can be used to lessen the effects of the various ions found in seawater. This review explains the mechanisms of different additives (e.g., polymers, surfactants, chelating agents, cross-linkers, scale inhibitors, gel stabilizers, and foams), how they interact with seawater, and the related implications in order to address the above challenges and develop a sustainable and compatible seawater-based fracturing fluid. This review also describes several previous technologies and works that have treated seawater in order to produce a fluid that is stable at higher temperatures, that has a considerably reduced scaling propensity, and that has utilized a stable polymer network to efficiently carry proppant downhole. In addition, some of these previous works included field testing to evaluate the performance of the seawater-based fracturing fluid.
... This fouling phenomenon can cause pipe blockages, reduction of heat-transfer energy, and enhanced corrosion, resulting in increased production and maintenance costs (Barton et al. 2022). Many industries are affected by fouling including oil and gas (Olajire 2015), drinking water distribution systems (Liu et al. 2016), reverse osmosis desalination (Supekar et al. 2018), geothermal systems (Gallup and von Hirtz 2015), and nuclear power (Rao et al. 2009). It has been predicted that annual expenses caused by fouling amount to 0.8 billion $US in the UK, 3 billion $US in Japan, and 9 billion $US in the US (Macadam and Parsons 2004;Li et al. 2017). ...
Nuclear facility discharge pipelines accumulate inorganic and microbial fouling and radioactive contamination, however, research investigating the mechanisms that lead to their accumulation is limited. Using the Sellafield discharge pipeline as a model system, this study utilised modified Robbins devices to investigate the potential interplay between inorganic and biological processes in supporting fouling formation and radionuclide uptake. Initial experiments showed polyelectrolytes (present in pipeline effluents), had minimal effects on fouling formation. Biofilms were, however, found to be the key component promoting fouling, leading to increased uptake of inorganic particulates and metal contaminants (Cs, Sr, Co, Eu and Ru) compared to a non-biofilm control system. Biologically-mediated uptake mechanisms were implicated in Co and Ru accumulation, with a potential bioreduced Ru species identified on the biofilm system. This research emphasised the key role of biofilms in promoting fouling in discharge pipelines, advocating for the use of biocide treatments methods.
... 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.
SiO2-EDTA composite particles are prepared by using nano-silicon dioxide (SiO2) as the loading particle and ethylenediaminetetraacetic acid (EDTA) as the scaling inhibitor. Then, SiO2-EDTA particle and polytetrafluoroethylene (PTFE) micro powder are added in water-based silanized maleic anhydride-g-poly(1,2-butadiene) (SiMLPB) to fabricate composite coatings with good anti-scaling and anti-corrosion properties. The water contact angles (WCA) of SiMLPB increase to a maximum of 103° with the addition of PTFE at 3 wt% and then decrease slowly; based on this formulae, the WCA improves to 109o when SiO2-EDTA is added up to 2 wt%. SiMLPB/PTFE coatings exhibit good corrosion resistance with the addition of PTFE; the SiMLPB/3%PTFE/2%SiO2-EDTA composite coating possesses impedance (|Z|0.01Hz) value at 2 orders higher than that of the SiMLPB/PTFE0 coating at low frequency, suggesting the much greater improvement in corrosion resistance due to the synergistic effects of adding nanoparticle as a surface modifier and EDTA as a corrosion inhibitor. The deposition of CaCO3 on this SiMLPB/PTFE/SiO2-EDTA composite coating reaches 0.0132 g/cm2 after 120 h scaling test, which is about 79% lower than that on the pure SiMLPB coating, resulting from the chelation of EDTA that promotes the formation of more unstable scales. The improvements in both anti-corrosion and anti-scaling performances are attributed to the hydrophobic function of PTFE and nanoparticle as well as the dual functions of EDTA at an appropriate addition of SiO2-EDTA.
Harsh scale buildup, such as calcium carbonate (calcite) and barium sulfate (barite), poses significant challenges in the oil and gas industry. While various scale inhibitors (SIs) are employed to mitigate this issue, there is a need for greener, more efficient, compatible, and affordable alternatives. Calcium compatibility often complicates the use of SIs, potentially leading to formation damage. Our group has recently synthesized a recyclable nanocomposite scale inhibitor made of superparamagnetic nanoparticles coated with a trisodium citrate linker to phosphonated poly(ether amine) (SPION-TSC-PPEA) and tested it against calcium sulfate (gypsum), a simple form of scale buildup. This study evaluates the recyclable nanocomposite scale inhibitor’s efficiency in mitigating calcite and Barite scales through static jar tests and high-pressure dynamic tube-blocking tests at 80 bar and 100 °C. The nanocomposite demonstrated high calcium ion compatibility, excellent inhibition efficiency against calcite, moderate efficiency against Barite, and maintained efficacy over five recycling cycles.
This study presents the synthesis and characterization of two polyelectrolytes derived from itaconic acid and vinyl sulfonic acid sodium salt. These polyelectrolytes were characterized by Fourier transform infrared (FTIR), nuclear magnetic resonance (NMR) and gel permeation chromatography (GPC). The biodegradability of the synthesized polyelectrolytes was assessed according to the ISO-10707 method. It was found that the biodegradation was higher than 30% for both polyelectrolytes, indicating that these compounds are moderately biodegradable. The aim of this work is to study the effect of the synthesized polyelectrolytes on the formation of CaSO4-scales and the corrosion of AISI─1810 carbon steel. Static precipitation experiments were carried out to investigate the effect of the polyelectrolytes on the precipitation of CaSO4-scale. The results showed that both polyelectrolytes are effective scale inhibitors under static conditions, with high efficiencies (> 80%) at low concentrations. The polyelectrolyte influence on the corrosion of AISI carbon steel was examined by open circuit potential (OCP), linear polarization resistance (LRP) and potentiodynamic polarization studies. The results showed that the polyelectrolytes provided corrosion inhibition efficiencies ranging from 60 to 90%. Compatibility experiments were carried out to investigate the stability of the synthesized polyelectrolytes in the corrosive media and to observe the influence of these compounds on the inhibition of CaSO4-scale. The polyelectrolytes were shown to be compatible with the corrosive solution. Furthermore, the results demonstrated that an increase in polyelectrolyte concentration led to enhanced scale inhibition.
The exploration potential within deep-water petroliferous basins holds great promise for oil and gas resources. However, the dearth of geochemical and isotopic data poses a formidable challenge in comprehending the intricate hydrocarbon charging processes, thereby impeding the comprehensive understanding of hydrocarbon accumulation mechanisms and models. Consequently, the establishment of robust source–reservoir relationships in deep-water petroliferous basins represents a pivotal challenge that significantly influences the exploration strategies and the comprehension of hydrocarbon enrichment dynamics within such basins. In this study, we introduce a novel approach, termed the “source–reservoir dynamic evaluation method,” tailored to investigate reservoir accumulation models in deep-water petroliferous basins. This method uses basin simulation technology to recover the thermal evolution history and hydrocarbon generation and expulsion history of source rocks, and on this basis delimits the hydrocarbon kitchen range. At the same time, the maturity of source rocks corresponding to crude oil and natural gas in typical reservoirs is calculated. Then, when the thermal evolution degree of source rocks adjacent to the reservoir reaches this maturity, the corresponding geological period is the main charging period of hydrocarbon. As a typical deep-water petroliferous basin, the Santos Basin in Brazil has abundant oil and gas reservoirs under the thick salt rock, but there are still some fundamental problems such as unclear oil–gas accumulation process and model. Therefore, in this paper, the main charging periods of typical hydrocarbon reservoirs are determined based on the internal relationship between the thermal evolution history of the main source rocks and the maturity of crude oil and natural gas, and then the hydrocarbon accumulation process is analyzed and the dynamic accumulation model is established. Finally, the favorable prospecting direction is pointed out. The results show that the oil and gas in the Barra Velha Formation in the Santos basin are mainly derived from the Itapema Formation lacustrine shale source rock, and the source rock is mainly developed in the Eastern Sag of the Central Depression, and its main hydrocarbon generation period is from the deposition period of Florianopolis Formation to the deposition period of Santos Formation. The main hydrocarbon expulsion period was from the deposition period of the Santos Formation to the Early deposition of the Iguape Formation. The oil and gas in the Barra Velha Formation were mainly charged from the Late deposition period of the Santos Formation to the Early deposition period of the Iguape Formation. During this period, the hydrocarbon migrated vertically along the normal fault formed in the rift period to the trap of the adjacent inheritance structural highs and accumulated in the reservoir, which was dominated by the accumulation model of the “lower generation-upper reservoir-salt cap”. Since the Barra Velha Formation has the characteristics of near-source accumulation, based on the hydrocarbon expulsion center and hydrocarbon expulsion intensity of the source rock of the Itapema Formation, the distribution ranges of 85% and 50% Pre-salt accumulation probability in the Santos basin were calculated by using the quantitative analysis model of the hydrocarbon distribution threshold. It is suggested that the next oil and gas exploration should be carried out in the paleo-structural highs and slope of Class I favorable area (the hydrocarbon accumulation probability is more than 85%) and Class II favorable area (the hydrocarbon accumulation probability is 85–50%).
Inorganic scale (salt) deposition in the oil and gas industry is a serious and widespread problem that requires timely measures for effective control and management. The process of formation and deposition of mineral salts depends on a large number of changing factors, which creates additional difficulties for predicting and controlling scale formation processes. The fields of Eastern Siberia, the formation waters of which belong to the category of brines with a mineralization of 250 g/l and more (in some cases more than 600 g/l), are characterized by the scale formation of complex composition (sulfate, carbonate and chloride salts). Scale deposits can occur in the near-wellbore zone of the formation, which can lead to a significant decrease in the productivity of production wells. Many fields in Eastern Siberia have a number of features that complicate their operation. Among them are low reservoir temperature (10–14 °C), reservoir pressure close to the saturation pressure and salinity (halitization) of the reservoir. In the practice of the global oil and gas industry, it has been repeatedly proven that the implementation of technologies to prevent scale deposits is much more technologically and economically efficient than removing already formed sediments. In this regard, the use of scale inhibitors (SI) is one of the key methods to combat the formation of salts. When scale deposits lead to disruption of the operation of submersible well equipment, technologies for continuous or periodic dosing of SI into the annulus of the well can be effective. To protect the bottomhole zone of the formation from scale deposits, the priority technology should be the injection of scale inhibitors or squeeze treatment into the formation under pressure.In this work, based on a set of laboratory filtration experiments, a module has been developed that allows calculating the volumes of scale inhibitor and process fluids required for SI squeeze into the reservoir. The successful results of two operations of SI squeeze into the formation of horizontal wells for protection against deposits of sulfate salts are shown.
The scale inhibitor squeeze treatment is an important method used in the petroleum industry to control formation of inorganic deposition within the oil production wells. This treatment increases the life cycle of petroleum production by preventing or reducing the formation and growth of salt crystals. In recent years, studies on inhibitor squeeze treatments have been expanding and diversifying with the goal of improving the lifespan and reducing treatment costs. This study reports an advanced bibliometric analysis from 1970 to 2023, illustrating the extent of research on inhibitor squeeze treatments to prevent the formation of inorganic scale, with a systematic survey since the first registered publication. It highlights the evolution of research reports, assessing the relationships between institutions, journals, and authors, identifying of potential needs to be addressed by future investigations.
Scale formation is a ubiquitous challenge commonly experienced in oilfield operations, energy production, water desalination, and cooling water systems. Researchers have been prompted to devise innovative technologies aimed at mitigating the detrimental technical, financial, and environmental impacts associated with scale accumulation. Among the various methods developed for scale mitigation, the use of scale inhibitors has emerged as a cost-effective, highly efficient, and reliable technique. Both organic and inorganic scale inhibitors have garnered significant attention for their remarkable effectiveness, often requiring minimal concentrations for optimal performance. Nonetheless, the high cost and environmental concerns associated with many conventional scale inhibitors have rendered them unsuitable for sustainable industrial applications. Consequently, there has been a recent shift toward the adoption of nanotechnology to develop scale inhibitors that are not only highly effective but also cost-efficient and environmentally friendly. These nanomaterial-based scale inhibitors have demonstrated the capacity to migrate porous media efficiently, extend the squeeze lifetime, and enhance overall scale inhibition performance. This chapter provides a comprehensive overview of recent advancements in the application of nanomaterials as effective, economically viable, and environmentally sustainable scale inhibitors.
Flow assurance in the petroleum business of the oil and gas industry ensures the efficient and continuous flow of hydrocarbons from production facilities to consumers. Impurities in oil and gas can cause corrosion and erosion, hydrate formation, scaling, and fouling, resulting in flow limits and reduced operating efficiency. The significant flow assurance issues must be managed through systematic exploration of effective mitigation and management approaches. The objective of this paper is to highlight the latest research in the field of flow assurance, including the application of superhydrophobic or omniphobic coatings to prevent scale growth, asphaltene precipitation, wax deposition, and hydrate formation. This review will provide new perspectives into the basic mechanistic mechanisms of deposition and blockage in oil and gas production systems, assisting in the development of novel methods compared to the employment of commercial chemical or mechanical techniques. Overall, the flow assurance engineers will gain new perspectives from this study regarding how to deal with the risk of pipeline blockage caused by the problems mentioned earlier.
Context
A complex supramolecular process involving electrostatic and dispersion interactions and asphaltene aggregation is associated with detrimental petroleum deposition and scaling that pose challenges to petroleum recovery, transportation, and upgrading. The homodimers of seven heterocyclic model compounds, representative of moieties commonly found in asphaltene structures, were studied: pyridine, thiophene, furan, isoquinoline, pyrazine, thiazole, and 1,3-oxazole. The contributions of hydrogen bonding involving water bridges spanning between dimers and π-π stacking to the total interaction energy were calculated and analyzed. The distance between the planes of the aromatic rings is correlated with the π-π stacking interaction strength. All the dimerization reactions were exothermic, although not spontaneous. This was mostly modulated by the strength of the hydrogen bond of the water bridge and the π-π stacking interaction. Dimers bridged by two water molecules were more stable than those with additional water molecules or without any water molecule in the bridge. Energy decomposition analysis showed that the electrostatic and polarization components were the main stabilizing terms for the hydrogen bond interaction in the bridge, contributing at least 80% of the interaction energy in all dimers. The non-covalent interaction analysis confirmed the molecular sites that had the strongest (hydrogen bond) and weak (π-π stacking) attractive interactions. They were concentrated in the water bridge and in the plane between the aromatic rings, respectively.
Methods
The density functional ωB97X-D with a dispersion correction and the Def2-SVP basis set were employed to investigate supramolecular aggregates incorporating heterocycles dimers with 0, 1, 2, and 3 water molecules forming a stabilizing bridge connecting the monomers. The non-covalent interactions were analyzed using the NCIplot software and plotted as isosurface maps using Visual Molecular Dynamics.
Alkaline surfactant polymer (ASP) flooding is an effective chemical enhanced oil recovery technique to recover more hydrocarbon from maturing oilfields. However, the alkaline slug with high pH would dissolve quartz mineral in the sandstone formation which will result in silicate scaling issue. Silicate scales would precipitate in the formation near the production wellbore region, and further deposit inside production equipment and facilities. Consequently, the productivity of a well will be impeded. Scaling issues can be treated using chemical scale inhibitor (SI) through the application of squeeze treatment, continuous injection, or both. Many commercial SI available are not intended to mitigate silicate scale and these chemicals possess low biodegradability. Hence, more environment-friendly or "green" SI are being developed and tested for their effectiveness on scale inhibition. This paper aims to evaluate the performance of developed green silicate SI in mitigating silicate scale formation. The developed green silicate SI are composed of pteroyl-L-glutamic acid (PteGlu) that has enhanced with polyamidoamine dendrimers, either PAMAM-1.0 or PAMAM-2.0. Several experiments are conducted to assess the SI compatibility with synthetic brines, SI thermal stability, as well as SI effectiveness in treating silicate scale formation in static and dynamic conditions. Static adsorption test is also performed to determine the potential of developed green silicate SI for squeeze treatment. Results revealed that all tested SI are compatible with different synthetic brines. Among all, PAMAM-2.0-PteGlu SI yielded the best laboratory results at its optimum ratio of 1:333. It has the highest thermal stability as it experienced 34% weight loss at temperature 95°C. This SI also achieved 73.1% effectiveness in static scale inhibition test. From dynamic tube blocking experiment, it also managed to delay silicate scale precipitation by 48 times longer than the base case. Besides that, the adsorption capacity of PteGlu SI on crushed sandstone is also improved by approximately 60% with the addition of PAMAM-2.0. The green silicate SI developed in this paper could be utilized as environment-friendly alternatives in silicate scale control.
A major concern with pre-salt processing is the water salinity and its high scaling potential. High standing output levels necessitate an effective scaling management strategy. One element of a successful program is scale prediction, which is frequently done utilizing the produced water's thermodynamic equilibrium.
This paper presents a methodology and algorithm to systematically calculate scaling index of produced water blend to be compared to representative brines which were defined for scaling inhibitor design tests. Thermodynamic calculations of calcite saturation indexes at relevant process conditions are evaluated for the mixture of produced wells streams and for the platform critical brine.
It was implemented an algorithm that integrates plant historian database to thermodynamic calculation routines and presents the results in a user-friendly web portal for proper visualization. Calcite saturation index is calculated using Pitzer activity model which is often used for calculations of inorganic scaling potential in high ionic waters. Produced wells flowrates are used for defining mixture fractions of the produced blend. For each platform there is one representative brine composition that was used for scale inhibitor design, herein called the platform critical brine. However, the compositions of wells produced water are updated as soon as new water analysis is available. The algorithm creates a scaling index (ISS) based on calcite saturation indexes that measures how far from the critical brine the produced mixture is in relation to calcite saturation index.
The ISS is evaluated systematically in daily basis for several platforms offshore Brazil. The results show how the different wells configurations (flowrates) impact the produced water blend criticality with respect to inorganic scaling. The implemented routine gives insight to production engineering personnel regarding potential problems with scaling and chemicals design. It can be used to assess if the platform critical brine should be updated, and possibly new chemicals designed. Additionally, the ISS can be used to optimize the topsides process conditions in specific scenarios.
The processing conditions and produced water compositions of pre-salt oilfields offshore Brazil results in scaling potential at topsides. This paper describes the methodology applied for monitoring the scaling potential systematically on a daily basis for several pre-salt platforms.
Silicate scaling is a concern that could result in formation damage and flow assurance issue. Phosphonates and phosphino-polyacrylates are widely used to treat many types of scale but they are not intended to treat silicate scale. Besides that, these inhibitors may have been considered as harmful substances due to their reported inherent biodegradability. Synergistic silicate scale inhibitors are current trends since cationic or anionic polymers alone is found not effective for silicate scale inhibition. The objective of this work is to assess the performance of polyamidoamine-assisted scale inhibitors for silicates. The experiment settings are simulating the environment in near wellbore region, such that higher temperatures and brine that is mostly pH neutral. The effectiveness of scale inhibitors is investigated through static bottle test and dynamic scale loop (DSL) test. The scale inhibitors are also characterized to determine their functional groups in aqueous state. The tendency of scale inhibitors to impede silicate polymerization process is also determined through the remaining concentration of monomeric silica in water after 72 hours. FTIR revealed that all scale inhibitors exhibit amine characteristic in water. Experimental results show that the polyamidoamine-assisted scale inhibitor, PAMAM G-2/PteGlu, is the most effective in mitigating silicate scale formation. It reduces scaling brine's turbidity as much as 94.8% after 72 hours at 90°C. In addition, it also minimizes silicate polymerization process by retaining almost half of the initial monomeric silica concentration. This also implies that PAMAM G-2/PteGlu inhibitor could reduce the tendency of silicate scale formation to 46% as compared to 97% of silicate scale formation without any inhibition at 95°C. From DSL test, PAMAM G-2/PteGlu inhibitor is also the most effective inhibitor. It prolongs the scaling time from 7 minutes to 339 minutes at 0.01 g/L inhibitor concentration. It is also 7% more effective than PAMAM G-1/PteGlu inhibitor in DSL test. In general, the performance of scale inhibitors for silicates can be arranged as: PAMAM G-2/PteGlu > PAMAM G-1/PteGlu > PteGlu > PAMAM G-2 > PAMAM G-1 from top to bottom. In this work, these environment-friendly products had demonstrated good silicate scale inhibition as well as synergistic effect. They could offer as alternatives to commercial scale inhibitors.
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...
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.
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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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.
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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?
Anyone who is vaguely familiar with oilfield operations has heard about the scale problem. However. there seems to be confusion about the extent of the formation and wellbore damage caused by scale in oil fields. To some, scale is not much of a problem because one seldom has a chance to see or physically examine actual samples of these deposits. Many scale deposits are, of course. located outside the well within the oil-bearing formation, where they are invisible. On the other hand, despite these analytical difficulties, some people think that scale is one of the major enemies in our daily oil- and gas-field operations.
I belong to the latter group, and I sincerely believe that there are few wells that do not suffer flow restrictions from scale deposits within the drainage radius inside the formation. within the wellbore, or in the surface equipment. If we try to estimate the loss of revenue caused by flow restrictions due to scale, we come up with astronomical figures. I have reason to believe that oil- and gas-field scale costs on the order of $ 1 billion/year in the U.S. alone. This sum should be considered a minimum.
I also believe that the scale problem is increasing. As our oil and gas reserves are depleted, we must produce these hydrocarbons under increasingly severe production conditions. More water production will favor many of the scale-forming conditions. In addition, we "pull" harder on our wells as less oil is being produced, thus favoring again all the scaling conditions. This means that the revenue losses resulting from plugging by scale will consume an increasing portion of our income as we deplete our reservoirs.
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There are a number of gaps in our knowledge of the principles and mechanisms involved in the squeezing process. Among the things learned through a series of tests was that adsorption isotherms, contrary to common theory, are not very important to the process. And some factors that have been largely ignored flow velocity, for example are very important indeed.
Introduction
The squeeze technique as a means of depositing chemicals in an oil-, gas-, or water-bearing formation finds extensive use in the petroleum industry. This trend was started after the first publications of Kerver et al. on squeezes utilizing publications of Kerver et al. on squeezes utilizing the adsorption-desorption characteristics of corrosion inhibitors. Later, Smith et al. and Kerver and Heilhecker applied the same ideas to the deposition of scale inhibitors in the rock matrix around the wellbore of a producing well. Here, again, the adsorption-desorption characteristics of chemicals provided the basis for the technique.
Recently, a different type of squeeze technique has been suggested by Miles. In this "precipitation" method. a dissolved chemical is first injected into the matrix and precipitated some distance from the wellbore. The precipitate is then partially redissolved by the oilfield brine at a very low but still effective concentration and transported back to the wellbore.
In a previous paper, we described our tests on the compatibility of inhibitors with constituents of common oilfield brines. From these earlier data, and from the results given here, we conclude that there is no clear-cut line between these two basic types of squeeze methods. Both mechanisms can occur concurrently, depending on the chemical nature of the inhibitor and on formation parameters.
However, the first mechanism (deposition based solely on adsorption-desorption characteristics) is to be preferred because it completely avoids formation damage that occurs when pores are plugged with secondary deposits.
A third mechanism of inhibitor squeeze has been proposed by Tinsley et al. The inhibitor solution proposed by Tinsley et al. The inhibitor solution enters small fractures and vugs during squeezing and later slowly bleeds back into the stream of produced water. This mechanism should not play any important role in formations consisting of a sand matrix where no fractures exist.
Basic Concepts of the Study
We think the literature shows a lack of information regarding the following:The basic mechanisms and principles involvedin the squeeze technique.The design and limitations of squeeze jobs asa function of formation parameters (rockmaterial, formation temperature, flow rates, etc.)and the chemical nature of the squeezedcompound.Methods of evaluating squeeze tests in thelaboratory and in the field.
We also believe that inadequate tools and methods are often used to conduct and evaluate actual squeezes. The "results" of these squeezes cause considerable confusion in some instances and may lead to misconceptions about the method and its value.
To develop some reliable information about the squeeze method, we conducted a series of laboratory and field tests.
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Dissolution rates of calcite, dolomite and magnesite were measured at 25 °C and pH from 3 to 4 as a function of salinity (0.001 M≤[NaCl]≤1 M) and partial pressure of CO2 (10−3.5≤pCO2≤55 atm). Experiments on calcite and dolomite crystal planes dissolution were performed in a batch reactor under controlled hydrodynamic conditions using the rotating disk technique. Dissolution experiments using mixed-flow reactors were also conducted on calcite and dolomite powders of 100–200 μm. Magnesite dissolution rates were measured using a batch titanium high-pressure reactor on 100–200 μm powders. The pH was measured in-situ using a solid-contact electrode in a cell without liquid junction. At pH∼4.0 and constant hydrodynamic conditions pH-independent calcite dissolution rate increases by a factor of 3 from 1 to ∼20 atm pCO2 and stays constant at 25 to 50 atm. These rates do not depend on NaCl concentration from 0.01 to 1.0 M and pH of 4 to 8. Calcite dissolution rates depend strongly on stirring between 200 and 2000 rpm at 2, 10, and 50 atm pCO2 suggesting mass transport control at these conditions. Both for polycrystalline samples and cleavage planes, dolomite dissolution rate increases with increasing pCO2 at 1≤pCO2≤10 atm and stays constant when pCO2 is further increased to 50 atm. These rates depend on stirring velocity and increases by a factor of 2–3 from 200 to 2500 rpm reflecting moderate transport contribution to dissolution at these conditions. Within the experimental uncertainty, dolomite dissolution rates are independent of ionic strength between 0.1 and 1 M NaCl and 5 to 50 atm pCO2. This is also confirmed by powder dissolution experiments performed in mixed-flow reactors. Magnesite dissolution rate increases by a factor of 3 at 0 to 5 atm pCO2 but remains constant from 5 to 55 atm pCO2.