Deepwater scale control in high temperature reservoirs has been a challenge since many scale inhibitors lose effectiveness at high temperatures due to molecular instability. It is well known that polymeric scale inhibitors have the highest thermal threshold up to 500°F (260°C) among the three basic types of scale inhibitors. The literature does however report certain degradation of polymeric scale inhibitors below 500°F (260°C). Therefore, a group of five polymeric scale inhibitors with various chemistries and molecular weights were selected for thermal stability investigation at 350°F (177°C). Evaluation of the scale inhibition performance was conducted for each chemical before and after exposure to high temperature. This evaluation used dynamic scale loop equipment so that the degree of performance degradation of each chemical could be determined. A reference scale inhibitor was used for comparison on the scale inhibition performance. Fourier Transform Infrared spectra were taken for scale inhibitors before and after subjected to high temperature to qualitatively characterize the influence of thermal aging. The calcium tolerance abilities were also studied for the five scale inhibitors. The work concludes by giving an in-depth evaluation of several novel polymeric scale inhibitors and determines their suitability for application in high temperature subsea environments. Furthermore, other criteria for deepwater scale inhibitor selection were discussed in this paper, including methanol and monoethylene glycol compatibility, and umbilical qualification.
For deepwater high-temperature scale control, a scale inhibitor should be selected by satisfying a wide range of requirements. These requirements may include thermal stability, high inhibition performance, calcium chloride completion fluid compatibility, methanol and monoethylene glycol compatibility, formation brine and sea water compatibility, compatibility with other chemicals, material compatibility, umbilical qualification, non-gunking, non-emulsification, and non-foaming. This paper will focus on the criteria of thermal stability, high inhibition performance, and calcium chloride completion fluid compatibility (high calcium tolerance). The rest of the criteria will also be discussed in this paper, but the corresponding test work will be included in the future work. Thermal stability of scale inhibitors has been an important issue for scale control in deep sea high temperature reservoirs. Scale inhibitors including polyphosphates and phosphate esters can generally only be used at temperatures less than 150°F (66°C) due to low thermal stability. Phosphonate scale inhibitors have excellent efficiency and adsorption characterstics to the formation. Unfortunately, these products generally become unstable at temperature around 300°F (149°C). Presently, low molecular weight polycarboxylates and derivatives are widely used for high temperature scale control because of their thermal threshold up to 500°F (260°C). Meanwhile, it has been reported in literature that adsorption properties of polymeric type scale inhibitors can be enhanced to allow extended squeeze lifetimes by incorporating novel end-capped technology for subsea scale control1 However, there are reports showing that polymers undergo certain degradations below 500°F (260°C) either in solid state or in solution2-5. The thermal degradation of polymeric scale inhibitors is generally affected by temperature, exposure time, carrier brine composition, pH, and oxygen level.
Use of 316L clad pipes are currently limited to 120 oC to avoid stress corrosion cracking. This work was undertaken to explore the possibility to extend the limits of 316L to higher temperatures. The testing is divided into a large scale test and a small scale test. The large scale test consists of a full ring pipe which is stressed externally and exposed internally to the test fluid. The work has also investigated the relationship between the test methods. It is the intention to find small scale tests which gives similar results as the large scale test. The small scale tests are four-point-bend (4PB) tests in accordance with ISO15156-31 and EFC172. The test specimens are made of approximately 3mm thick clad material where the carbon steel backing has been machined off. The tests were conducted at 135 oC with a partial pressure of 0.02 bar H2S. CO2 pressure was approx 11 and 1 bar for the small and large scale test respectively. In situ pH was adjusted to approximately 5.3. Chloride concentrations were between 40.5 and 41.8 g/l Cl-.
The use of 316 L is limited in ISO 15156-31 to 60 oC with a pH2S of 15 psi/1.03 bar. Also in the Technical Circular 1:20073, Table A.2, the additional limits:
- For S31600: 93 oC, 1.5 psi/0.103 bar pH2S, Chloride concentration of 5,000 mg/l and a pH of ≥5.0
- For S31603: 149 oC, 1.5 psi/0.103 bar pH2S, chloride concentration of 4,000 mg/l and a pH of ≥4.0 However, Norsok M-0014 allows for use up to 120 oC in production environments without oxygen. A test program was undertaken to explore the possibility of extending this temperature limit for environments with moderate pH and salt content. The purpose of the testing was to qualify clad pipe consisting of a 3mm inner layer of 316L and a backing of X65 carbon steel. The use of 4PB testing for clad pipe is not common practice as the carbon steel is removed and only a 3 mm thick 316L sample is tested. It was therefore decided to also include a large scale test with a full ring pipe to verify the 4PB test results.
mulated reeling. A pipe string with 4 welds was reeled in a full scale reeling rig. A strain cycle representative of a reeled installation was used. Mechanical testing and determination of microstrain. Tensile testing was conducted in accordance to EN 10 002-1:20015 for ambient temperature and EN 10 002- 5:19926 for elevated temperature. The yield strength was found for test (135oC) and ambient temperature for both the 6 o'clock (tension) and 12 o'clock (compression) position on the pipe. Vickers hardness measurements were undertaken on the sectioned girth weld and on the clad surface in accordance with BS EN ISO 6507-18 using a 5kg applied load. Rockwell C hardness measurements were also conducted on the clad surface in accordance with BS EN ISO 6508-18 using a 150kg applied load.
The design of coatings must be adequate to protect pipelines under long-term, severe environmental conditions, including the extreme climatic conditions that will apply in the North before the pipe is installed and operation begins. Practices and standardised methodologies for evaluating and qualifying pipeline coatings for application in northern pipelines are discussed. Results from laboratory and field experiments, carried out under the conditions to which coatings will be exposed during construction, are presented. Based on one-year laboratory experiments in which samples were exposed to temperatures as low as -45oC and three-year data from the field experiments, it is concluded that Canadian Standards Association (CSA) standards CSA Z662, CSA Z245.20 and CSA Z245.21 adequately cover evaluation of coatings for northern pipelines. However, in order to evaluate the effects of low temperatures, the specimens should be exposed for at least four months. Coatings qualified by CSA Z245.21 system B1 and B2 are less affected by exposure to low temperatures than those qualified by CSA Z245.21 system A1 and CSA Z245.20.
Northern gas pipelines include the Alaska gas pipeline, Mackenzie valley gas pipeline, Northern route gas pipeline, and Arctic gas pipeline. The Mackenzie valley gas pipeline was first envisioned in the mid-1970s, to tap Mackenzie delta reserves. A modified route, resembling the Arctic gas Mackenzie valley routing of the 1970s, was proposed in 2002. The application to construct the Mackenzie valley pipeline has been submitted. Since managing risk will be a key consideration in the construction and operation of northern pipelines, it will be essential to acquire and share knowledge on the properties of construction materials, including the steel itself, the girth welds that are made in the field and the coating and cathodic protection (CP) that will protect the pipes from corrosion. This knowledge must address the effects of the harsh northern environment - such as extreme temperature conditions and ground movements - on degradation processes. Procedures and practices for achieving effective control of external corrosion on buried or submerged metallic piping systems are well documented. Standard procedures include the use of polymeric coatings and CP(1-3). The coating is the first line of defence of a pipeline against external pipeline corrosion. If the coating fails, the CP should act as a backup protecting those areas of the pipe where the coating has failed. A pipeline is susceptible to external corrosion or stress-corrosion cracking (SCC) only when both systems have failed. The performance of an external pipeline coating depends on the events taking place during the five stages of the coating lifetime(4-5): manufacture, application, transportation, installation, and operation. Many test procedures have been developed to evaluate pipeline protective coatings in various stages. Standards have been developed by various standards-making organisations for these tests(6-7). Construction of pipelines in the harsh northern conditions, with temperatures as low as -45oC, will impose unique challenges with respect to protective coatings. It is critical that the coatings are effective in protecting the pipelines in severe environmental conditions during both construction and operation.
Cathodically generated surface films on steel specimens have been discovered to vary in composition and protective nature depending upon the electrolyte composition, pH and applied potential. Three electrolytes were studied, pure 3.5% NaCl, artificial seawater and an alkaline solution of composition similar to that found beneath a disbonded land-based pipeline coating. Specimen Potentials varied from free corrosion to -1400 mV (Ag/AgCl/3.5% NaCl). Films grown as a result of applying Cathodic Protection (CP) were analysed by X-Ray Diffraction and Scanning Electron Microscopy and corrosion rates were determined gravimetrically. Films grown in 3.5% NaCl were composed of iron corrosion products and were found to be more coherent and protective than calcareous deposits grown in artificial seawater. The ratio of magnesium to calcium of specimens exposed to artificial seawater influenced the film protective nature. Films grown in the land-based electrolyte were composed of a mixture of iron corrosion products and calcium carbonate with little magnesium present. Current Criteria for CP used to control land- and sea-based systems will be assessed in view of a better understanding of what happens at the metal /electrolyte interface upon the application of Cathodic Protection.
Cathodic Protection (CP) is one of the foremost techniques used worldwide to minimize corrosion of buried or immersed metallic structures. The technique involves applying a potential so that current flows from the anode through the surrounding electrolyte (soil or water) to the structure surface. In concept it is thought that if a sufficiently negative potential is applied, then corrosion of the metal structure should be mitigated. When CP is applied two reactions occur; reduction of oxygen and reduction of water. The first reaction occurring as potentials are made more negative is the reduction of oxygen dissolved in the electrolyte to form hydroxide ions (Cathodic Reaction 1). Reduction of oxygen is limited by the amount of available oxygen, which is typically 8ppm dissolved in water at ambient temperature . At typical free-corrosion potentials of steel, this reaction is diffusion controlled. It can be shown theoretically that when reduction of oxygen is the dominant reaction, typically implying applied potentials less negative than -1.17 V (CSE), and assuming air-saturated solution, then the pH of the metal surface is never more alkaline that 10.57 . This is because the diffusion of oxygen to the metal surface follows the same path as the diffusion of hydroxyl ions away from the surface, so the surface pH is controlled by the oxygen concentration in the bulk solution. The second reaction that occurs is reduction of water (Cathodic Reaction 2). This reaction starts to occur as the applied potential is made more negative than -1.170 Volts (CSE). Since the reaction only involves water as a reactant, it is not subject to mass transport control though at high current densities it can be affected by blocking of the surface by hydrogen bubbles. It has been found that as the applied potential is made more negative, the pH at the metal surface becomes progressively more alkaline.
A detailed review is made over 125 distinct field cases of sour weight loss corrosion ( SWLC), i.e. all uniform and localized corrosion types out of any cracking, on oil and gas wells, lines and process facilities, covering nearly 45 distinct fields/ reservoirs. The fluid corrosiveness is classified in 3 categories, from a negligible corrosiveness in 40 to 50% of the cases (both in oil and gas production), to a moderate attack (typically within 1 mm/yr) in most of other cases and lastly to a very severe corrosion in a few cases. Although quite rare, these severe corrosion cases are impressive as corrosion rates are currently above 10 mm/yr, even in apparently mild conditions. Interesting enough is the fact that these 3 categories seem to correspond to 3 distinct corrosion mechanisms. Leading and secondary corrosion factors are sorted out from this analysis. The flow velocity and flow regime are shown to be the most leading factors of the transition between negligible and intermediate and severe corrosion categories. It is also highlighted that very severe corrosion cases require "pit promoters" (sulfur, oxygen, bacteria…) and a galvanic effect with surrounding non corroding surfaces. It appears from reviewed experience that these promoters are mostly extraneous to produced fluids, apart from sulfur depositing from sour gases. It is worth noting that most factors have a similar corrosion contribution in oil as in gas production systems, in wells as in lines. This suggests that the basic corrosion mechanisms involved on these different facilities are not so different. Preliminary indications are given on possible corrosion mechanisms involved in the 3 corrosion categories. Research and Development (R&D) studies recently launched around the world on H2S corrosion are thus strongly encouraged to study and challenge these proposed mechanisms. They are also welcomed to take as much benefit as possible of the reported experience.
A first paper addressing the management of weight loss corrosion in sour conditions (wells, lines and process facilities) was published in 2006(1). Part of this paper was devoted to a detailed review of the field experience gathered within the author's company. This paper particularly highlighted the fact that there is not yet sufficient understanding of the key factors and mechanisms of the Sour Weight Loss Corrosion (SWLC) to conduct an extensive, serious mechanistic corrosion prediction. Until significant progress is made, a well-documented field case remains the best way to address and begin to predict SWLC factors and mechanisms, at least for analogue cases. The present paper is a 2nd step on the way to SWLC prediction: from an extended collection of field data and puts forward tentative SWLC mechanisms. It aims to define a first set of empirical prediction criteria (to be published as a 3rd step) while looking at promoting R&D activities, focused on key mechanisms and parameters. Contrary to the 2006 paper, this new article only focuses on corrosion prediction for Carbon Steel equipment without any attention given to material selection or to any other corrosion control solution.
Unbonded Flexible pipes have inner armour of stainless steel made from a helix structure of an S-shaped continuous strip. Typically the selected stainless steel grade has been AISI 316L (UNS S31603). The recent development of lean duplex materials has provided attractive alternatives due to the increased strength, good corrosion resistance and lower cost. The carcass in an unbonded flexible pipe is exposed to the conveyed fluid or gas but protected from marine seawater surroundings. This paper describes acceptance criteria for autoclave testing in CO2 / H2S environments. Observations are made on initiation of pitting and selective corrosion on LDX 2101 (UNS S32101). Results from both short and long term tests are evaluated in order to validate an acceptable duration for autoclave testing.
Unbonded flexible pipes are typically used offshore for risers connecting floating production units with wellheads on the seabed and for flowlines resting on the seabed. The flexible pipes transport oil, gas, water and other fluids used in oil and gas production. Flexible pipes are often used instead of rigid pipes due to the ease of installation and superior fatigue properties. The innermost layer, the carcass, is made from a stainless steel strip typical 316L (UNS S31603). Stronger alternatives such as 22% chrome duplex (UNS S32205) and 25% chrome duplex (UNS S32750) has been used for deep water applications in addition to fields with highly corrosive production fluids. The resent developments in lean duplex stainless steel grades have provided an interesting alternative material with better mechanical properties, similar corrosion resistance at a very competitive price compared to austenitic 316L grade. Structure of a flexible pipe The most important layers in an unbonded flexible pipe are the Carcass, the inner lining, the pressure armouring, tensile armouring and outer sheath. A typical flexible pipe is illustrated in Figure 1. Additional layers providing the flexible pipe with insulation or internal anti friction tapes may also be integrated, however that is regarded outside the scope of this paper. The design and qualification of flexible pipes are given in API 17J1. A short introduction of the primary layers is given below: Carcass. The carcass is folded from a stainless steel strip. The most important purpose of the carcass is to carry the inner lining in an accidental state where the pipe is empty and the outer sheath is damaged. In such a case the external water pressure acts on the inner lining, meaning that the carcass is the only structural load carrying layer. Typically, the material for the carcass has been 316L. Inner liner. The inner liner is the pressure barrier for the contained media. The inner lining is extruded on the carcass. The material is selected according to the maximum operating temperature and the water content in the contained media. The material is typically polyethylene, polyamide (Nylon) or polyvinylidene fluoride (PVdF). Pressure armour. The pressure armouring is composed of cold worked carbon-manganese steel wires with an interlocking profile. This layer supports the inner liner when the pipe is pressurised.
It is estimated that corrosion costs industries hundreds of billions of dollars annually. Many of the costs directly related to corrosion may be mitigated and managed with continuously monitored corrosion transmitters as part of a comprehensive plant-wide control strategy. Process parameter effects related to electrochemical corrosion may be minimized via direct, continuous corrosion feedback for active control and optimization of neutralizing agents, e.g. inhibitors. This paper details the investigation into corrosion control strategies and provides recommendations on optimal process control strategies regarding inhibitor use.
In oil production fields, corrosion monitoring is made with electrical resistance (ER) probes or coupons. The control of corrosion in these tubes is based on the results of the coupon or ER probe rate determination and then manually adjusting the inhibitor flow periodically to maintain a desired corrosion rate. Experience with coupons indicates an average weight loss over the given test time. ER probes have a short life cycle. In this application, a linear polar resistance (LPR) probe is selected to provide a level of high accuracy, real-time measurement, and longer life. There are two key benefits realized by migrating to a highly accurate, long-life real-time LPR corrosion measurement. First, by controlling and reducing the volume of injected inhibitor while maintaining the system design integrity level, real-time feedback identifies corrosion rate changes that may be affected by other factors. Factors unrelated to the liquid chemistry include differences in temperature, pressure or system leaks. Secondly, compared to the non-real-time coupon method, the real-time LPR probe reduces risk to personnel servicing valves and related equipment in wells during maintenance cycles.
EXPERIMENT ON LIVE OIL WELL:
In oil production fields, water is injected into the well, measured in barrels of water per day (BWPD), to force oil up and out of the well. The control of corrosion in these injection tubes is based on the results of the coupon or ER probe rate determination and then manually adjusting the inhibitor flow periodically to maintain a desired corrosion rate. This experiment used an LPR probe. The calculation of inhibitor dosing is dependent on several variables, including water injection, temperature, flow velocity, pressure, pH and conductivity. In order to use a coupon, it must be exposed for a minimum time (at least a month) and at best, it provides an average corrosion rate for that exposure time. In this experiment, a simplified approach was used -the inhibitor flow rate was altered by several gallons per minute in a month long study. ER probes were used as a comparison with the results provided by the LPR probe. Information from the probes was downloaded on a daily basis. An oil well was selected that consumed over 16% of the total inhibitor used site-wide, or 300 liters per day (77 gallons per day). They reduced the dose in 19.45 L/day (5 gal/day) decrements until obtaining a maximum corrosion rate of 0.05 MMPY (2 MPY). The chart below is an example of the inhibitor variation versus corrosion rate, in 12-hour increments.
The Sour Water Joint Industry Program (JIP) has led to the development of new data and insights related to corrosion in H2S-dominated Ammonium bisulfide sour water systems, commonly found in a number of refinery processes. The JIP, termed as Sour Water Phase I, provided a new methodology and software prediction tool targeted towards predicting and quantifying corrosion in hydro-processing units, specifically reactor effluent air cooler (REAC) equipment and associated piping. Based on comprehensive laboratory data, multiphase flow-modeling and numerical data interpolation, the Sour Water Corrosion Prediction Software (prediction tool) facilitates corrosion prediction, failure prevention, optimized material selection and safe operational practice as a basis for compelling cost saving and improved maintenance planning in refinery operations. This paper evaluates the efficacy of the JIP-based Prediction System when applied to real plant evaluation situations in a variety of refinery conditions. The paper also details appropriate methods of utilizing the data and functionality within the software tool to ensure optimized prediction accuracy. Case studies identifying pitfalls to avoid while using the software model are also provided along side comparison of predicted corrosion rates with measured rates from inspection. The case studies and trends presented demonstrate the importance of rigorous flow modeling and need for accurate characterization of effects of Ammonium Bisulfide NH4HS concentration and environmental parametric data variables in assessment of corrosivity of alkaline sour water systems.
Predicting corrosion in refinery alkaline sour water systems is a complex engineering task that has traditionally been approached qualitatively using relatively simplistic rules of thumb, based on experience and anecdotal case studies1-3. Refinery sour water corrosion problems and failures may result in serious injury, significant costs and lost production and since they may manifest in multiple refinery units, including hydrotreaters and hydrocrackers, as well as sour water strippers and FCCU units, the problem becomes a critical operational issue. Even though these problems are widely seen in refineries, till recently, very little quantifiable corrosion data incorporating key parameters have been published in the open literature. The approach used to handle sour water corrosion issue in many refineries has been simply to focus on empirical findings derived from evaluations of operational experience. Hence, there has been a critical need for a more precise and quantifiable basis to characterize ammonium bisulfide corrosion for a variety of materials under actual service conditions. Such a need led to the development of the Sour Water Corrosion Joint Industry Project (JIP), conducted and managed by Honeywell and supported by a number of leading global, refinery operators. As will be shown herein, lost opportunities resulting from refinery sour water corrosion can range from $1 million to $10 million per incident in terms of over alloying, increased inspection and required unit revamping. Failures associated with sour water corrosion in REAC system can lead to over $50 million in financial impact associated with damage. Over the last few years, additional data resulting from the Sour Water Corrosion JIP research and validation of such JIP data/rules in refinery plant experience have been published.
In chemical plants, there are lots of equipments for chemical products. Among these, heat exchangers are the most prominent. Because of this, heat exchanger maintenance is important in the maintenance management in chemical plants. While management techniques have been established for various fluids types, heat exchanger damage control is difficult when cooling is carried out using uncontrolled fluids such as raw river water. Heat exchanger damage has been increased due to the use of cooling water with unmonitored water quality in recent years. As a result, investigations were carried out into the measurement equipments that allow monitoring of the damage occurring in heat exchangers. As a result of these investigations, a corrosion monitor for on-site measurement was selected and adopted for use. In the cooling water system, the coupled multielectrode array sensors (CMAS) was found to be suitable for measuring the corrosion rate and the electrochemical noise method (ENM) was suitable for measuring changes in cooling water quality. This paper introduces a comparison for experimental evaluations of the two electrochemical methods, CMAS and ENM, and basis for the design of the corrosion monitoring device for cooling water system.
In chemical plants, there are lots of equipments for chemical products. Among these, heat exchangers are the most prominent. Because of this, heat exchanger maintenance is important in the maintenance management of chemical plants. While management techniques have been established for various fluids types, heat exchanger damage control is difficult when cooling is carried out using uncontrolled fluids such as raw river water. Heat exchanger damage has increased due to the use of cooling water with unmonitored water quality in recent years. As a result, investigations were carried out into the measurement equipments that allow monitoring of the damage occurring in heat exchangers. Particular attention was paid to the measurements carried out in the tubes of the equipments, which are parts that perform the actual heat-exchanging. Of the numerous problems that were uncovered with these investigations, problems related to sensors shape, in light of the structures of the regions to be measured and corrosion (which is the process that leads to the most damage) were very significant. Numerous measurement equipments have been used to investigate these problems. As a result of these investigations, a corrosion monitor for on-site measurement was selected and adopted for use. Figure 1 shows the degraded state of river water used as a source for cooling water. The types and concentrations of the chemical agents that were previously used for cooling water quality management have been restricted in to avoid the degradation of the global environment. As a result, the management of cooling water has become more difficult. For this reason, the use of problematic water for cooling purposes was intentionally pursed, and investigations were carried out concerning the optimization of facility management in response to changes in water quality treatment methods and materials used.
COOLING WATER SYSTEM:
The cooling water system and corrosion control system for cooling water is explained in this Section.
There is currently interest in the use of a 6 Mo stainless steel (UNS N08367) for applications on naval vessels. While the base material has good resistance to corrosion in marine environments, the welds are in a non-optimal metallurgical condition. Therefore over-matched filler metals need to be used when welding this 6-Mo stainless steel in order to assure proper corrosion resistance. The importance of weld dilution by the base metal is demonstrated. Two Ni-Cr-Mo alloys (UNS N06022 and N06059) were used to produce welds of various dilution amounts. These were then tested in high chloride environments to evaluate how pitting and crevice corrosion might be affected by changing filler metal and the amount of dilution from the base metal.
The U.S. Navy is reported to have an annual cost of corrosion of about $1.2 billion annually associated with corrosion maintenance and repair of about 360 combat ships1. Ongoing efforts to decrease this cost include awide variety of topics and technologies. One part of these cost reduction efforts includes a fundamental change in the hull design for surface ships. A new design has been developed know as the advanced double hull (ADH). This new design uses austenitic stainless steels to achieve several objectives, including reduced maintenance and repair costs compared to conventional designs. Figure 1 shows a schematic of the new ADH design compared to a conventional hull design2. This new design eliminates the need for transverse framing leads and reduces the overall number of parts or frame members. The cost savings associated with this design more than offsets the added costs of using more expensive austenitic stainless steels. In order to assure resistance to crevice corrosion over the life of the vessel, UNS N08367 was chosen as the preferred material for seawater wetted areas of the ADH design. Other 300 type stainless steels are also being considered for areas in the ADH where the corrosive conditions over the life of the vessel are not as demanding. While corrosion resistance is the primary material selection criteria, stainless steels also have other desirable features, such as high strength, improved toughness, and are readily weldable. Austenitic stainless steels are also non-magnetic, which improves the ability of a ship to avoid detection by the enemy. The currentmaterial design objectives include increasing the yield strength above current ship hull materials (such as AH36 and DH36 ferritic steels), increasing the dynamic fracture toughness, exhibit non-ferromagnetic behavior, having 100% resistance to stress corrosion cracking, and avoid crevice corrosion over the life of the ship. In addition, the weldability of the selected materials is a primary materials requirement as the ADH is welded structure. Since welding puts the material in a non-optimum metallurgical condition, an over-matched filler metal will be required to meet the corrosion and strength design goals. The over-matched weld filler metals normally used for UNS N08367 are in the Ni-Cr-Mo family of alloys, as these materials have excellent resistance to crevice corrosion in chloride environments.