Accurate representations of the thermochemistry and phase equilibria of relevant molten salt constituents and their aggregate behavior are critical to the development, design, operation, and licensing of any molten salt reactor (MSR). This need is currently being addressed by the creation of a dedicated, high quality/validated MSR thermochemical database, the Molten Salt Thermal Properties Database-Thermochemical (MSTDB-TC). MSTDB-TC is being populated with prioritized models and values for vapor species, and liquid and crystalline phases of chloride and fluoride fuel and coolant salts with relevant fission product and transuranic elements, and more recently with corrosion-relevant systems with chromium, iron, and nickel. Multi-cation crystalline and melt solution models are being incorporated, including newly developed relations as necessary, to obtain real system behavior.

Accurate bacteria population monitoring is important in oil and gas fields to mitigate microbiologically influenced corrosion (MIC) prevent reservoir souring and optimize biocide treatment strategies. Serum serial dilution testing (SSDT) is a flawed yet widely accepted traditional method for bacteria testing in the oil and gas industry. The serum bottle test is cumbersome to perform correctly in the best of conditions and impractical to use in most if not all oil and gas field applications. The SSDT culture method returns an indirect estimate of bacteria populations that are often misleading and inaccurate due to basic assumption of the test and users attempts to stream line the method.It is important for operators to understand the drawbacks of the SSDT method and be aware that alternative accurate field ready techniques for bacteria population measurements are available. This paper reports the work performed to a develop a new method to detect bacteria in oil and gas fields that is used to select test and apply fit for purpose bacteria control chemicals.The new methodology has many advantages over other commonly used methods such as the SSDT and ATP tests. The new technique provides a rapid bacteria measurement that can be performed wholly at the well site with real time results. The method gives highly accurate data simple to use and is compatible with oilfield production chemicals fluid chemistries and system microbiology. The approach uses a bacteria metabolism based assay technique that utilizes fluorescence spectroscopy to obtain a fluorescence value that is proportional to the total number of living bacteria present in a sample. However the new method is unique in that the user converts the fluorescence value into meaningful data such as colony forming units per mL or even number of equivalent bug bottle turns. The conversion is based on the results of thousands of experiments comparing the fluorescence value with accurate laboratory bacteria measurements (e.g. plate counts and nucleic acid base testing) performed on field waters from a wide variety of sources.The new technique has been used in many oilfields throughout the world and several case histories are presented where the technique has been used to successfully optimize biocide treatments. This new approach to bacteria monitoring is unique and allows immediate real-time post treatment testing to ensure biocide applications are effective.

Inorganic zinc (IOZ) silicate coating was previously applied to partially fabricated low alloy, 21/4 Cr-1MoV, high temperature, hydrogen, reactor vessels for long-term storage corrosion protection prior to final welding and post weld heat treatment (PWHT) at 690-720°C (1274-1328°F). The need for complete coating removal to mitigate the known embrittlement and weld cracking that can occur after welding and PWHT led to the development of a novel, environmentally friendly method to remove IOZ to trace levels below 1 ppm. 

To maintain production levels, oil fields in the Middle East increasingly require water injection to maintain pressure in hydrocarbon reservoirs. The injected water increases the water cut of the produced fluids, resulting in a very corrosive mixture for metallic piping. Therefore, nonmetallic pipe systems have become more widely accepted as alternative pipe materials for transporting produced fluids and injection water.

The work here is the culmination of many years of prior effort in the development of an atmospheric corrosion model and accompanying sensors. Atmospheric corrosion is a complicated process where many factors interact to determine if it occurs and its severity. These factors can be separated into
three general categories: environmental, surface salts, and materials.

Material selection for downhole applications has become more difficult as the number of alloys continues to increase.  On one hand, stainless steels like 316 offer a relatively low initial cost, but are not suited for many severe applications or environments.  Other alloys, like MP35N, offer considerable strength and corrosion resistance, but with a much higher cost.  Thus, an attempt has been made to create an alloy that spans the considerable gap between the 300 series of stainless steels and the nickel or cobalt base alloys.  The resulting 6% Mo stainless steels offered increased strength and corrosion resistance without a drastic cost increase.  The first generation of superaustenitics still falls considerably short of the strength and corrosion resistance provided by established nickel or cobalt-base alloys.  In an attempt to further bridge the remaining gap, a new superaustenitic stainless steel has been developed that maintains the attractive cost of the 6% Mo alloys, but enhances both corrosion resistance and strength to open up environments that were too severe for 6% Mo alloys.  The development of this alloy along with localized corrosion resistance, qualification testing, and mechanical testing are discussed.

Duplex stainless steels were born and have been actively developed by European companies since 1935. Their properties make them very attractive compared to equivalent austenitic grades: higher resistance to stress corrosion cracking higher mechanical characteristics and lower alloy cost. They are today commonly used for Oil & Gas applications. However these materials cannot be used below -50°C (-58°F) because their toughness strongly decreases below this temperature. In addition they may require special precautions for welding in order to keep the ferrite content in heat affected zone lower than 65% as recommended by several standards.This paper will present the recent development of a 22%Cr duplex stainless steel grade with enhanced weldability and low-temperature properties. This material is based on the UNS S31803/S32205 designations and obtained by means of slight changes in the chemical analyses and production route compared to the conventional duplex grades. A strong increase in toughness values is obtained at low temperature pushing back the limits of use from -50°C (-58°F) to -100°C (-148°F). Toughness values obtained on samples up to 150 mm thick will be provided. In addition there is no need to control the minimum heat input to obtain the appropriate ferrite content in heat affected zone.This paper will describe the main service properties of this material focusing especially on corrosion and comparing its performance to a conventional 22%Cr duplex. The results of corrosion tests obtained in sour environment will be given. They were conducted on welded specimens in a solution containing 100 g/l NaCl at pH 4.5 under 0.5 bar H2S using the constant load test method. Stress corrosion cracking results obtained in synthetic seawater with and without cathodic charging will also be provided.Keywords: Stainless Steels; Duplex; Ferrite content; Oil & Gas; Low temperature; Weldability; H2S; Corrosion

Accounting for 1.2 million bbls/day the Bakken shale plays a significant part in the North American unconventional boom. The formation is characterized with low porosity and permeability where wells exhibit high initial production rates and steep decline curves. Mitigating excessive decline is paramount to maintain return on investments.The system conditions and the produced water in the Bakken shale causes challenges that can impact productivity. The water composition is generally characterized with high total dissolved solids (TDS) resulting in high scaling tendencies for various species. In addition corrosion is also a challenge due to high TDS high downhole temperature (~250 °F) medium CO2 partial pressure (40-50 psi) and varying shear.A chemical qualification process is herein discussed where a combination corrosion- and scale inhibitor has been developed. The chemical is a synergistic blend of corrosion inhibitor actives and surfactants for corrosion mitigation and solids control combined with scale inhibitor and chelating agent for high iron tolerance scale control. The product had to be tailored to a chemical injection system that involves concurrent injection of several other production chemicals into a fresh water line that is subsequently injected downhole at elevated temperatures in a high TDS brine.Key words: Scale inhibitor corrosion inhibitor high TDS compatibility combination production chemical Bakken

This production asset located in the deep-water offshore Brazil, producing heavy oil in the range of 16 to 24 oAPI. Mudline caisson separators with electrical submersible pumps (ESPs) are used to process fluids from multiple wells and boost them to the receiving floating production, storage, and offloading (FPSO) vessel(1). There are significant flow-assurance and corrosion challenges in operating the asset. One of the challenges is the production fields have limited subsea umbilical, necessitate the use of
multifunctional products to maintain the field’s integrity and mitigate any flow assurance and scale issues.

Oil and gas production field requirements to maintain asset integrity and scale control are very diverse. In an operator’s field in Latin America, the conditions across several wells required the co-injection of corrosion and scale inhibitors. The brine composition of these wells is challenging due to relatively high concentration of calcium ions as well as the presence of iron. The selected scale and corrosion inhibitors need to be compatible with brine and with each other without negatively impacting the absolute performance of the individual products. An additional practical challenge for product selection was imposed by the extreme remote location of the field requiring the product to perform at an optimal dosage without increased transportation and logistics costs.  

This paper describes the results from screening studies conducted with a series of corrosion inhibitor product formulations using different static and dynamic lab performance evaluation test methods. As the primary corrosion inhibitor actives are oil-soluble by nature, focus was given to formulating the product with an appropriate selection of solvents, such as methanol and isopropanol, and surfactants to achieve the desired compatibility with the brine and scale inhibitors. The final products were identified, and an optimal product dosage was arrived at based on tests conducted under typical and aggressive conditions representative of the field. However, due to the diversity of conditions and corrosion severity levels across multiple wells in this field, corrosion prediction simulations were run for unmonitored wells to estimate a baseline corrosion rate and build confidence in the recommended corrosion inhibitor product dosage. The validation of the prediction for monitored wells with ER probes will also be discussed in this study.  

Large underground, carbon steel tanks are used for interim storage of liquid radioactive waste. The current corrosion control program needs to be updated to account for the susceptibility to pitting corrosion of waste tanks due to the halide content of the secondary waste.