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ABSTRACT The use of polymer based chemical inhibitors has the advantage of utilizing chemical, macromolecular, and compositional (blends or block copolymers) towards chemical inhibitors whether it is for corrosion or scaling issues. It is important to understand the multi-phase condition of production fluids whether it is extraction or circulation (oil and gas vs geothermal brine). It is also important to understand the mechanism and the long-term action of inhibition from the fluid to the surface that is being protected. This talk will highlight the principles and work in investigating various corrosion and scaling inhibitors for the production and process industries. In particular, the use of block-copolymers and hyperbranched oligomeric design in inhibitors is of a high interest because of the multi-dentate and stability (or predictability) of their solubility in various phase conditions. While a number of these examples are highlighted in the design of new materials and dosing methods, it is important to stress the cost- performance ratio of chemical inhibitors and their long term viability for continuous dosing from upstream to downstream. The work of the author also involves a number of analytical methods and testing methods that can be used to augment circulation fluids under high pressure and temperatures. INTRODUCTION Metals in their elemental state or as pure metals (reduced) are eventually oxidized under ambient conditions except for noble metals such as Au, Pt, etc. It is an electrochemical event, the result of which is the degradation of properties if not the formation of then films of metal oxides that we call rust. The economic cost on structures, machines, vehicles, is enormous based on studies by the National Association of Corrosion Engineers (NACE) to the total to US$ 276 billion or 3.1% of the country's Gross Domestic Product (GDP). Various mitigation techniques, about US$ 121 billion is spent, a majority of which is on the use of corrosion protective coatings. These are either alarming number for most industries or create a variety of business opportunities and scientific/technical challenges. In a March 2016 NACE report, “IMPACT – the International Measures of Prevention, Application, and Economics of Corrosion Technologies,” the global cost of corrosion was estimated to reach up to US$ 2.5 trillion or approximately 3.4% of the global GDP. The cost to process, production, and transport, industries is staggering. Various protocols have be used to significantly slow down the rate of corrosion. The most common of which includes the application of protective and barrier coatings, which can employ corrosion inhibiting additives onto metal surfaces.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.95)
- Health & Medicine (0.94)
- Energy > Renewable > Geothermal (0.67)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT Chemical inhibition in the presence of silica sand deposit has been reported as a cause of severe localized corrosion attack in CO2-saturated brine environments. This paper suggests a new mechanism for explaining physics behind the localized corrosion attack based on experimental evidences. The effect of sand size and deposit type on localized corrosion attack in the presence of imidazoline type inhibitor is also experimentally investigated in CO2-saturated brine solution. Smaller silica sand particles (diameter less than 44 micron) are found to cause less localized corrosion attack in comparison to larger sand particles (In the range of 250-750 micron diameter). Localized corrosion attack in the presence of paraffin deposit is also negligible compared to silica sand deposit. INTRODUCTION Under-deposit corrosion (UDC) has frequently been reported as a cause of failure in the oil and gas industry. Under-deposit corrosion often results in severe localized corrosion attack; this is difficult to monitor, predict, and mitigate. Galvanic cells established between covered and uncovered regions of the metal surface, resulting in severe localized corrosion. Monitoring of localized corrosion is problematic because predicting the location of deposit formation is difficult and it happens along the pipeline in random locations. Mitigation is challenging because corrosion inhibitors do not efficiently protect the areas of the pipe covered by deposit. The inhibitors may even accelerate localized corrosion attack under deposits by the creation of more pronounced galvanic effects. One of the best tools to mitigate under-deposit corrosion is pipeline pigging. It is important to mention that not every pipeline is piggable and even those lines that are piggable may suffer from extensive corrosion damage if the pigging frequency is not adequate. Different types of deposits have been reported in the oil and gas industry. In 2005, de Reus, et al. reported that field deposits are most frequently silica sand associated with produced oil. Deposits can be divided into two main categories:
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- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT In order to compare laboratory-synthesized materials for corrosion inhibition capabilities, corrosion inhibitor assessment methodology is introduced that accounts for the onset of corrosion inhibition during incubation time, that often is ignored when single corrosion measurement procedure is used. The robust analysis described in this paper uses a combination of open circuit potential, electrochemical impedance spectroscopy (EIS), and linear polarization (LPR) followed by polarization in simulated pore solution. Combining these electrochemical tests, provides a technique to monitor the corrosion inhibition capability as a function of time. Additionally, comparative analysis can be made between EIS, LPR, and polarization results. The advantages and limitations will also be discussed in this paper. INTRODUCTION Concrete is the second most common manmade material after potable water. Nearly one cubic yard of concrete is placed per year per person. Assuming a typical service life, up to 30 times this amount of existing concrete in various states of deterioration also exists. Reinforcing steel bars, or rebars, are installed in concrete to improve its poor tensile strength. However, reinforcing steels are susceptible to corrosion in concrete with the presence of chloride ions or reduced pH due to carbonation. The expansive stress induced by corrosion product formation cracks and spalls the concrete cover that can cause hazardous consequences such as structural failure. Application of admixture or surface applied corrosion inhibitors is one approach possible for reinforcing steel corrosion protection. Physical and electrochemical approaches utilized for monitoring inhibitor performance or corrosion in concrete are documented in former studies and standards. However, there is a lack of evaluation protocols to quickly test materials with unknown corrosion inhibition performance. Typically, corrosion inhibitors form a passive film on reinforcing steels that is inert to corrosion reactions. This passive film formation is time-dependent, hence testing methods ignoring the time dependence may not appropriately evaluate newly synthesized inhibitors. In addition, traditional techniques require weeks (mass loss, surface morphology imaging) or even months (outdoor exposure) to determine the performance of a corrosion inhibitor, which is not practical for screening a large number of new inhibitors. In order to screen a number of potential corrosion inhibition materials sufficiently, a combination of open circuit potential (OCP), electrochemical impedance spectroscopy (EIS), linear polarization (LPR), and polarization tests are utilized in this work. The purpose of this paper is to demonstrate a protocol for evaluation of corrosion inhibitors for reinforcing steel in simulated concrete pore water solution containing added chlorides, not to distinguish the performance of specific proprietary chemicals or reveal the nature of the newly synthesized chemical inhibitors. BASF considers the identity of the chemicals studied in this paper as proprietary information.
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- Water & Waste Management > Water Management > Water & Sanitation Products (1.00)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.35)
Materials and Corrosion Risk Mitigation Associated with Flowback of Acid Stimulation Fluids
Hernandez, Sandra (Chevron Energy Technology Company) | Goodman, Lindsey (GATE, Inc.) | Knobles, Mark (Chevron Deepwater Asset Development - Gulf of Mexico) | Schutz, Ronald W. (ARCONIC Titanium and Engineered Products)
ABSTRACT Acid stimulation is a growing practice to improve well productivity in the deep water subsea environment. Spent acid “flowback”, in which the acid returns are transported through the subsea system and topside processing facilities, is not a routine activity and poses significant materials, corrosion and degradation risks. Live acid contains corrosion inhibitor to protect the metallurgy during treatment operations, however most, if not all, of the corrosion inhibitor is spent shortly after entering the reservoir. When the well is opened to production, the spent acid is flowed back containing little or no corrosion inhibitor to protect the wellbore equipment, flowlines/pipelines, risers, tapered stress joints, or topsides piping/equipment. In addition to corrosion, environmental cracking is a major threat in acid fluids especially for Titanium alloys. This presents a challenge for the diligent operator where mitigation processes must be in place. A multi-year testing program was undertaken to assess the compatibility of acid stimulation chemicals with the materials comprising downhole, subsea, and topsides equipment of deepwater projects in the Gulf of Mexico. Two different acids were tested, one composed of hydrofluoric and acetic acids (HF/organic), and another composed of hydrofluoric, hydrochloric, and acetic acids (HF/HCl/organic). This paper summarizes the results of this testing and outlines recommendations for different alloys so that the operation can be performed in a safe manner without compromising the integrity of the production system. INTRODUCTION Matrix acidizing, also called acid stimulations or acid jobs, are increasingly utilized to improve oil production from deep water reservoirs. The typical primary objective of an acid stimulation is to dissolve precipitated scale, sand, clay, and fine particles from produced water or oil, or remove damage caused by drilling, completion, or workover fluids, all of which can cause formation damage/plugging and drastically reduce productivity. Acidizing is not a routine activity. The live or ‘fresh’ acid is typically bullheaded into the well via the production tubing. The return of acid, during which the acid is transported through the subsea system and topside processing facilities, is called ‘flowback.’ Flowback is not a routine activity and poses corrosion and materials degradation risks. The acid composition used in the field is chosen dependent upon the mineralogy of the well and the type of damage. For example, acidic mixtures containing hydrofluoric (HF) acid are commonly used where sandstone is prevalent; hydrochloric acid (HCl)-containing acids work well in carbonate formations. Combinations of HF and HCl, along with organic acids like acetic and formic acid are also used, depending upon mineralogy and scale composition. A common acidizing procedure consists of several steps, including injection of a solvent, an acidic pre-flush, injection of the live, or ‘fresh’ acid into the well, injection of an overflush, and then return of the ‘spent’ acid mixture.
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- Geology > Mineral (0.88)
- Geology > Geological Subdiscipline > Mineralogy (0.45)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.48)
ABSTRACT Application of Vapor phase Corrosion Inhibitors (VCI) for protection of various industrial and military equipment from corrosion during storage and overseas transport provides numerous advantages. When VCI inhibitors are being applied during the process of corrosion protection they will enable strong protection of the equipment during storage and transport without additional time and money needed prior to putting equipment in operation. During transport the equipment travels through various climate zones experiencing changes in temperature and humidity that are favorable to corrosion. Changes in humidity and temperature levels during transport even at very short distances can create moisture that condenses into water. Properly chosen combination of Vapor phase corrosion inhibitors enables the equipment and its components (especially electrical components) to resist the corrosion caused by moisture and aggressive saline environment. The requirements that need to be fulfilled during the application of inhibitors vary depending on the conditions of the application as well as required time limits of corrosion protection process. Vapor phase Corrosion Inhibitors (VCI's) are thermo-stable and they do not damage ferrous or non-ferrous metals. Inhibitors will not affect electrical, physical or chemical properties of lubricants if used in lubrication systems. The paper includes laboratory testing data and application methods of shrink film, impregnated foams and coatings containing vapor corrosion inhibitor (VCI) that are being applied in conservation process of industrial and military equipment. The experimental part of this paper will include validation of effectiveness of this system using standard test methods according to ASTM, MIL-SPEC, NACE and DIN standards. INTRODUCTION Vapor corrosion inhibitors are organic compounds that have a low pressure saturated steam under atmospheric conditions and inhibit corrosion by adsorption to the metal surface. They alter the kinetics of electrochemical reactions. Most effective inhibitors are the ones whose vapor pressure is in the range 10-5 - 10-7 mm Hg [1-3]. Inhibitors diffuse trough the gas phase and are adsorbed to the metal surface in thickness of several nano layers and to protect it from corrosion, Figure 1.
- Water & Waste Management > Water Management > Water & Sanitation Products (1.00)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT This study looks at the issues faced by operators with low temperature sandstone reservoirs of only 40°C and 54°C and the challenges these low temperatures brought which include high MIC for sulphate scale control and poor chemical retention & release properties observed during the reservoir condition corefloods. These findings will be compared and contrasted with two other higher temperature (71°C and 95°C) sandstone reservoirs where phosphonates and phosphate ester chemicals have been evaluated and deployed in the field. The findings from this detailed coreflood study and review of previous experimental/field deployed scale squeeze treatment data shows that phosphonates work very well at elevated temperatures; at and above 70°C where their stronger retention and excellent release profiles makes them a favored chemical for such treatments. However at lower temperatures these molecules are not well retained on the rock and it is the phosphate ester chemicals that are more effective and provided the longer squeeze life to its respective MIC value. Comments on the interaction/performance of polymer scale inhibitors will also be made for these low temperature conditions. The implication of these findings show that phosphate esters offer the potential for extended squeeze lifetime in the <50°C sandstone reservoirs that are being developed in Northern Norway (Barents Sea) and the shallow subsurface depth, cool reservoirs being developed in offshore Brazil. INTRODUCTION Oilfield scales are inorganic crystalline deposits that precipitate from brines present in the reservoir and production flow system. Precipitation occurs as the result of changes in the ionic composition, pH, pressure and temperature. The primary scale formation mechanisms and the scale resulting from these mechanisms are detailed in Table 1. Scaling Tendency and Scale Mass as a Function of Temperature Sulphate scale (particularly barite) forms as produced water (a mixture of Ba-, Sr-, Ca-rich formation water and sulphate-rich seawater) cools. Barite scale tendency increases with decreasing temperature, because barite is less soluble at lower temperatures. This is shown in Figure 1 where the barite scale tendency for a formation water (barium = 110ppm) and seawater (sulphate = 2900ppm) blend is tested between 5 and 75°C. The barium sulphate scaling tendency (thermodynamic driving force for precipitation) is 5-6 times higher at 5°C than at 75°C (Figure 1). The challenge of controlling scale at low temperature is therefore well-recognised.
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- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Sulfate (1.00)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.79)
- North America > United States > Texas > East Texas Salt Basin > Alba Field (0.99)
- Europe > United Kingdom > North Sea (0.89)
- Europe > Norway > North Sea (0.89)
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ABSTRACT The inhibition of calcium phosphate (Ca/P) precipitation by natural organic polyelectrolytes, bio- and hybrid polymers, homo- and co-polymers of acrylic acid and maleic acid containing different functional groups was examined in aqueous solution. Additionally, commonly used phosphonates were also evaluated as Ca/P inhibitors. It has been found that performance of additive (polymeric and non-polymeric) as Ca/P inhibitor depends upon additive concentration, ionic charge, and molecular weight. Based on the inhibition data, the ranking in terms of decreasing effectives is: biopolymer > hybrid polymer > natural organic polyelectrolytes. Among synthetic polymers the ranking order is: terpolymer > co-polymer > homopolymer. Results on phosphonates evaluation reveal that compared to synthetic polymers, phosphonates show poor performance as Ca/P inhibitors. INTRODUCTION The formation of calcium phosphates is important in the fields of biology, dentistry, geology, and industries such as potable water production, waste water treatment, milk pasteurization, and automatic dishwashing. In addition, calcium phosphates are important in industrial water treatment (i.e., cooling, boiler, desalination of sea/brackish waters) where precipitation and deposition of calcium phosphates prevents effective heat transfer, leads to interference with fluid flow and facilitates the environment for corrosive processes to occur on equipment surfaces. Effective control of calcium phosphate deposits continues to challenge the academic researchers and industrial technologists. Recently, the problem of calcium phosphate (Ca/P) scaling in industrial water system has become increasingly important. Higher orthophosphate levels are being encountered in cooling waters due to increased water reuse, availability of low quality make-up water such as waste water plant effluent, phosphate based fertilizer contamination, and the use of organic phosphonate scale and corrosion inhibitors which are degraded to orthophosphate. The increased orthophosphate levels, combined with alkaline operating conditions can lead to the formation of highly insoluble Ca/P scale deposits which are normally attributed to hydroxyapatite [Ca5(PO4)3OH, HAP]. In cooling water systems however, it is not the HAP which is initially formed, but instead a precursor phase is formed which is widely known as amorphous calcium phosphate, Ca3(PO4)2. Factors influencing the precipitation of Ca/P in aqueous system include, pH, temperature, ionic strength, process contaminants.
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- Water & Waste Management > Water Management > Lifecycle > Treatment (0.89)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (0.75)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (0.68)
ABSTRACT The protection effectiveness of commercially available vapor corrosion inhibitors powders with different particle size was evaluated. Conventional powder size of and nano-particle powder inhibiting effectiveness was compared using the vapor-inhibiting ability (VIA) NACE TM 208. Optical microscopy post VIA corrosion tests revealed that the particle size of inhibitor powder has a significant influence on the degree of protection. The nano-particle inhibitor showed a corrosion rating grade 4 and more than 41% decrease on the corrosion rate both in electrochemical tests and continuous exposure tests compared with the inhibitor with coarse particle size inhibitor. Surface coverage also showed improvement mainly due to increase of effective surface area and the partial pressure of vapor inhibitors as powder particle size decreased. Adsorption energy was roughly -16,740 J/mol for the nano-particle size inhibitor, while, adsorption energy is roughly -13,660 J/mol for the coarse-particle size inhibitor, indicative of a stronger physical adsorption to the metal surface for nano-particle than the coarse inhibitor, leading to better corrosion protection. Laser Doppler Anemometry (LDA) measurement using the Doppler shift in a laser beam to measure the flow velocity showed a velocity of 6 ft/sec for nano-particle and uniform flow. While coarse particle inhibitor had a lower velocity of 3-4 ft/sec and non-uniform flow. INTRODUCTION Corrosion inhibitors can adsorb to a metal surface, protecting it from the environment by forming a non-reactive, hydrophobic layer that prevents corrosion. To be effective, an inhibitor will interact with the anodic or cathodic sites to slow oxidation and reduction reactions. Vapor Phase Corrosion Inhibitors (VCIs) rely on vapor pressure for transport of active inhibitor compounds. VCIs form a bond with the metal surface and create a barrier layer to minimize corrosive ions on the surface. VCIs can be used alone or can be incorporated into packaging materials, oils, chemicals and coatings. Some applications have been demonstrated for long term (2 years or more) storage of LNG gas piping in Abu Dhabi, power and desalination plant boiler tubes, also in Abu Dhabi, and gas pipe flanges in Wales. Other applications include above ground storage tanks with underside corrosion between the tank bottom plate and its concrete foundation. The mechanism of the NANO-VCIs involves the transport of the inhibitor to the metal surface and the inhibitor interaction with the metal substrate to form a protective film. When added to a liquid coating, the inhibitors react with water and dissociate. After application, as the liquid coating cures, the charged inhibitors migrate and adsorb onto the bare metal surface; adsorption occurs as a result of electrostatic forces between the electric charge of the metal and the ionic charges of the inhibitor molecules. Once attached to the metal, the tails of the inhibiting molecules produce a highly hydrophobic film that repels water and other corrosive species, which in turn reduces corrosion. A good level of corrosion protection can be obtained with an inhibitor that forms a passive micro-phobic layer on the metal surface using micron sized powder particles. However, as a result of the larger particle size, gaps may exist between the particles that are deposited on to the metal surface. This lack of coverage provides an opening for corrosive species to attack the unprotected surface [Figure 1].
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- Water & Waste Management > Water Management > Water & Sanitation Products (1.00)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas (0.91)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT PBTC (2-phosphonobutane 1,2,4-tricarboxylic acid) has become the work horse for calcium carbonate scale inhibition in cooling water, water reuse, and water treatment applications operating at the edge of control technology. Economically, this stressed system inhibitor allows cooling tower operation at higher concentration ratios resulting in decreased water usage and discharge. The inhibitor also allows the reuse of water that would otherwise be discharged, possibly after costly treatment. It permits the use of less than desirable water in other applications. Performance and limits of this inhibitor were first characterized in a 1985 paper. This paper expands these findings based upon over thirty years of field application and recent laboratory studies to elucidate behavior and performance of this “go to” inhibitor over a broad range of conditions. Test conditions simulated varied from easy to treat low concentration ratio HVAC towers, to water reuse applications, and into the range of hydrofracturing flow back brines. Data developed and reported includes inhibitor minimum effective dosage requirement as a function of saturation ratio (scaling index), temperature as it affects rate, residence time, and PBTC dissociation state. Performance as the sole inhibitor, and when applied with commonly used polymers, is also discussed. This paper stresses the upper limits for the inhibitor when used as the sole treatment, and in combination with other inhibitors. Both synergism and antagonism were observed for the inhibitor blends, with the interaction type being a function of ratio. Future reports will expand the PBTC performance data base to include calcium sulfate and barium sulfate scale control. INTRODUCTION PBTC Models For Minimum Effective Dosage Existing models for calculating the minimum effective dosage for scale control have been applied to industrial and oil field scale control treatment optimization since the 1970s. Standard correlations are routinely used in developing the models. The models typically apply to a single inhibitor. There is a driving force limit for each inhibitor, above which scale control cannot be achieved regardless of the inhibitor dosage. Knowing the upper limit is critical for selecting the optimum treatment program and in specifying control limits for a system such as an open recirculating cooling tower or membrane system. Limits for individual inhibitors have been well documented. Studies have been conducted to determine the impact of blending inhibitors on the upper driving force limit. Upper driving force limits' as expressed by calcite saturation ratio, were measured for calcium carbonate inhibition by individual inhibitors and combinations. Results were evaluated and blends were found to:
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- North America > United States > Texas > Harris County > Houston (0.17)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.36)
ABSTRACT Evaluation of corrosion inhibitors for high temperature (HT) upstream oilfield applications can be challenging due to fixed fluid volume testing typically encountered in laboratory testing. A series of laboratory testing methodologies were conducted to further elucidate the factors which affect laboratory corrosion inhibitor performance in high temperature conditions. Under certain HT conditions, inhibitor performance may be skewed due to testing effects which may occur in closed cell testing such as Fe saturation and/or scaling of the test fluids which may artificially lower the overall general corrosion rate. This testing program was designed to minimize these effects and ensure that corrosion inhibition in laboratory testing is identified solely due to performance of the inhibitor. For these studies, corrosion measurements in stirred autoclaves were performed by linear polarization resistance (LPR) or with weight loss measurements in rotating cage autoclaves (RCA). Surface morphology of corrosion products, scale deposition and effects of localized attack were evaluated by microscopic evaluations. Factors affecting inhibited and uninhibited general corrosion rates measured in laboratory test environments such as brine composition, effect of scale inhibitor inclusion, effect of metal surface area to fluid volume ratio, and method of acid gas charging were evaluated. INTRODUCTION Amine based film forming corrosion inhibitors (CI) have been used extensively to control internal corrosion experienced as a result of production of oil, gas, and produced water in upstream environments. Although extensive research in various test methods have shown the ability to qualify corrosion inhibitors at temperatures < 100°C, a better understanding of the parameters which affect corrosion processes at temperatures > 100°C is necessary. CO2-dominated fixed volume fluid testing has long been a challenge of laboratory corrosion inhibitor evaluations as brine chemistry, pH, concentration of Fe, etc. can change throughout the duration of the test affecting both the overall general corrosion rate and subsequent performance characteristics of the inhibitor. This phenomenon is especially evident in high temperature (HT) testing as elevated temperatures encourage the formation of passivating FeCO3 and/or mineral scales which can result in an overall artificial reduction of the corrosion rate. Closed cell laboratory testing relies on a fixed fluid volume in which accumulation of corrosion by-products can alter bulk fluid chemistry as well as the resultant steady state corrosion rate. Laboratory simulations differ from field conditions as the bulk fluid properties in the field will be less prone to significant changes in fluid chemistry encountered in fixed volume tests. Therefore, proper CI selection in laboratory evaluations should mimic as closely as possible the corrosive condition expected in the field.
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