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The recovery of petroleum resources from previously untapped shale reserves significantly impacts the global energy market. Effective management of limited water resources and control of microbial contamination in all process fluids are crucial to the sustained quality of production fluids. Microbiological contamination in untreated waters is recognized in the oil and gas industry as posing a high risk of production fluid souring by allowing the growth and metabolism of sulfate reducers. In addition to hydraulic source water contamination, it is expected that microbes can be introduced into shales at the time of drilling, necessitating the treatment of source waters to target existing downhole contamination.
A two-part biocide treatment strategy has been extensively evaluated in controlled laboratory studies. The synergistic combination treatment involves the co-injection of dimethyl oxazolidine (DMO), along with the industry benchmark glutaraldehyde (GLUT). Laboratory testing showed a combination of treatments applied at 1:1 to 1:4 GLUT to DMO active ratios were highly synergistic against bacteria. This ratio provided a rapid kill of sulfate-reducing bacteria (SRB) and acid-producing bacteria (APB), as well as extended control in downhole conditions. Testing conditions were designed to simulate downhole conditions in a North American shale play; subsequently, the shale play was selected for field trials.
A field-wide application of GLUT:DMO in the Niobrara formation was performed from 2012 to 2013. This case study reports 70 hydraulically fractured wells comprised from 25 well pads that received the GLUT/DMO combination treatment. The treatment was successful in maintaining low bacteria counts in the flowback/produced water, using liquid culture media (three positive SRB vials or less). Key advantages of this new treatment strategy include lower total biocide usage versus competitive biocides, an improved environmental (ecotoxicity) profile, enhanced performance at an alkaline pH, and compatibility with process additives.
The use of cured-in-place pipe (CIPP) and Carbon Fiber Reinforced Polymer (CFRP) liners for the rehabilitation of nuclear power plant raw water systems can result in significant cost savings, increased system reliability, and extended piping life. These systems also include the use of internal mechanical seals. The cost advantage for installation of CIPP alone may reach 10:1 for the nuclear power industry versus excavation and replacement of buried carbon steel piping. This paper will present recent examples of these applications, including unique requirements faced in the nuclear industry such as more detailed material and system qualification, licensing, and working within outage and operational restrains, e.g. Limited Condition of Operation (LCOs).
The mass transfer behavior of electroactive solutes from bulk solution to a metal surface under subcooled boiling and pool boiling conditions was investigated using a self designed novel pool-boiling device. This device employed hot oil circulation to heat the specimen until the nucleate boiling take place on the surface of the specimen. The electrochemical method was successfully employed to obtain the mass transfer rate on a boiling surface by measure limiting current density. The effects of subcooled boiling temperature and heat flux on mass transfer on surface were studied. The results show that under subcooled boiling condition the mass transfer coefficient is increasing with the increase of the solution temperature attribute to the increase of diffusion rate. Under pool boiling condition the mass transfer coefficient is increasing with the increase of heat flux when the heat flux is under 90 kW/m2 due to the enhancement of the bubble generated forced convection.
The field experience in H2S + CO2 corrosion which was first reported in 20061 has been significantly increased, some of which has been made available in the literature. Several new cases are included in this paper. This experience has been compiled and extensively analyzed during the last few years, which has allowed some recurrent corrosion effects to be found, and some lessons learned on how to address or mitigate such effects. Six distinct recurrent findings are listed in this paper.
These findings have been analyzed in a very simple approach, which can be summarized as follows:
Under significantly sour conditions and despite a permanent contact with water, the H2S + CO2 carbon steel corrosion rate typically remains low, as long as the following conditions are met:
1. There are sufficient anions and cations at the steel surface to ensure quick FeS precipitation at the steel-water interface,
2. Precipitation kinetics are high enough to ensure the precipitation reaction to be immediate at the interface, hence producing a dense protective corrosion product layer,
3. No detrimental factor is present that would alter this protective layer, neither locally nor on extended parts of the surface.
On the other hand, H2S + CO2 corrosion of carbon steel is possible, as long as water is present, if any of these 3 conditions is not fulfilled.
Though this summary does not provide a detailed mechanistic description of H2S + CO2 corrosion, it provides a very simple way to approach this corrosion threat, while also showing essential tendencies and suggested barriers that future mechanistic description should be able to explain.
The report discusses cathodic protection (CP) experiences on the world’s longest, most complex crude oil and liquid hydrocarbon transportation system; having 24,738 kilometers (15,372 miles) of pipeline throughout North America. Since initial construction of the first pipeline in 1949, infrastructure has continually been enhanced and improved to meet the needs of the Company’s shippers. The expansion has resulted in areas of the mainline corridor where up to seven (7) parallel pipelines are contained within the same right-of-way (ROW).
The evolution of construction materials over the course of the Company’s long operating history has contributed to the diversity within the ROW. Early coating systems included asphalt, coal tar epoxy, and mummy-wrap. Polyethylene tape coated pipe was installed in the late 1960’s and 1970’s. Since the 1980’s, the Company has favored high performance coatings such as fusion bonded epoxy, dual layer epoxies, and high performance composite/powder (HPCC/HPPC). Presently, the ROW includes an assortment of pipeline vintages with various diameters and coating types which can consequently result in unbalanced CP levels.
This Project includes in-depth research and analysis of various methods, procedures, and materials beneficial in regulating and maintaining appropriate levels of CP in complex multi-pipeline corridors. Associated rectifiers are all furnished with remote monitoring equipment and the majority of test stations have been retrofit with coupons enabling remote surveillance of real time CP/AC potentials and corresponding current densities. All Project pipelines are regularly evaluated using inline inspection tools equipped with technologies to identify metal loss, and some of the pipelines have been inspected using inline tools capable of evaluating CP currents flowing in the pipe wall. These data have been consolidated and used to generate a computational model providing a more accurate representation of CP levels on each pipeline within the shared ROW. The purpose of such a model is to refine testing procedures, develop corrective measures and establish new guidelines for optimizing CP operation and effectiveness within ROWs containing multiple pipelines.
Rationally managing and harmonizing CP levels within such multifaceted arrangements is necessary to accommodate the pipelines having a high current demand, while avoiding the detrimental effects of overprotection on adjacent, newer pipelines with high efficiency coating systems.
Like most metals, fine forms of titanium metal, such as powders and metal shavings, pose a significant fire hazard and, when heated in air, an explosion hazard. While large titanium metal pieces are difficult to ignite, these pieces will become ignitable under certain circumstances, such as dry chlorine, red fuming nitric acid and oxygen-rich environments. Any titanium fires and/or explosions occurring outside these well known conditions are considered unusual and unique.
An unexpected explosion occurred in the vent line connecting at the top of a titanium reactor that was used to make a fire-retardant fabric. The fabric was made by mixing 1,2,4,5-tetramethylbenzene (durene) and nitric acid in the presence of plentiful water at 1380C (2800 F). The line consisted initially of a short section of 6-inch titanium pipe and fitting before connecting to stainless vent line. Titanium seemed to be compatible with reactor conditions. There was no knowledge or expectation that these conditions could pose fire or an explosion hazard in titanium. That is, it was not feasible to create red fuming nitric acid or other known incompatible chemicals under reactor conditions.
Nevertheless, explosions occurred in the vent line but not in the reactor after 3 ½ years of operation. In this presentation, the cause for this accident will be discussed based on the findings in examining samples from the vent line and the results of high-temperature tests.
Coupons simulating the coating defects have been used to evaluate cathodic protection level of steel structures. This paper aims to provide requirements for coupon AC current density as affecting AC corrosion of cathodically protected steel pipelines. The field investigation into the polyethylene coated 400 mm diameter natural gas transmission pipeline paralleling a 25 kV AC transit system which operated at frequency of 50 Hz was carried out. The steel coupon was connected to this pipeline with the cathodic protection applied. The four parameters, that is, coupon on-potential, coupon instant-off potential, coupon DC current density, and coupon AC current density were acquired by using the new coupon technology with high data sampling rate of 0.1 ms and 16-bit. It was thought that the requirements to regard the coupon AC current density for a single period of commercial current frequency as affecting AC corrosion could be: 1) polarity reversal; 2) consistency with commercial current frequency; 3) small distortion factor of a waveform.
Haile, Tesfaalem (Alberta Innovates – Technology Futures) | Wolodko, John (Alberta Innovates – Technology Futures) | Wilkie, Rio (Alberta Innovates – Technology Futures) | Tsaprailis, Haralampos (Alberta Innovates – Technology Futures)
Water plants constructed to process brackish and fresh water sources for in-situ thermal oil sands production have noted failures associated with corrosion. The approach to resolve observed problems may depend on the local or upstream operating conditions, and may involve improved monitoring capabilities, additions of chemicals, and/or material selections. The unpredictable occurrences of serious corrosion issues related to the complex water chemistry make it difficult to choose the appropriate preventative and mitigation measures. This is further complicated by the effects of temperature, pressure, and flow turbulence on the equilibrium concentrations of the different species. Considering that the water chemistries are continually changing, it is beneficial to establish operating windows for the different chemical components and determine the effect of operating parameters such as turbulence and temperature. A better understanding of the singular and interactive effects of dissolved ions and gases in the waters is a necessary precursor for an effective integrity management program.
The current paper details selective findings related to corrosion of brackish water systems used for in-situ thermal operations. The effect of pH, bicarbonate and oxygen were studied using model brackish water and the results show that the corrosion rates were significantly impacted by the pH and oxygen levels, while the reduction of the bicarbonate (alkalinity) content of the brackish waters did not sufficiently reduce the overall corrosion kinetics.
Double Loop-Electrochemical Potentiokinetic Reactivation (DL-EPR) is a valuable technique to test Type 304 stainless steel (SS) materials and components for the presence of grain boundary chromium depletion and assess material sensitization. This has practical relevance for the evaluation of susceptibility to intergranular stress corrosion cracking (IGSCC) of welded structures. The present study reports on work to develop DL-EPR methodology applied to UNS S30400 SS pipe butt-welds of relatively small size and having fusion zones irregular in shape, both of which present experimental difficulties to electrochemical evaluations. The primary challenge was to determine how to practically get an accurate DL-EPR signal from the relatively small heat affected zone (HAZ) that may be susceptible to IGSCC. A simple method was used to isolate the area of study that led to a relatively small solution potential drops during DL-EPR measurements. Measurements on a control material showed that smaller IR drops correlated directly with a measurably smaller degree of sensitization as measured by DL-EPR. A prototypic butt-weld was used to join two different heats of materials, one of which had a low carbon with high delta-ferrite content and the other of which had a high carbon content and no delta-ferrite. The DL-EPR process could detect the delta-ferrite in the low carbon material and also isolate DL-EPR degree of sensitization measurements to the HAZ of the high carbon material. In the process of this DL-EPR analysis, comparisons were made with two different grain boundary etch techniques.
Kobayashi, Kenji (Nippon Steel & Sumitomo Metal Corporation) | Hara, Takuya (Nippon Steel & Sumitomo Metal Corporation) | Mizuno, Daisuke (JFE Steel Corporation) | Ishikawa, Nobuyuki (JFE Steel Corporation) | Tada, Eiji (Tokyo Institute of Technology)
Hydrogen Induced Cracking (HIC) is a major issue for line pipe steels exposed to sour environments. In general, 5.0 wt% NaCl and 0.5 wt% CH2COOH solution with 0.1 MPa H2S provided by NACE TM0284 as solution A is used to evaluate the HIC resistance of steel products. However, in many cases, the test condition is too severe compared to the actual field conditions. Therefore, establishment of an appropriate HIC evaluation method under mildly sour conditions has been the subject of considerable investigations in recent years. In this study, the influences of balance gas (N2 and CO2) and specific solution volume on pH stability and sour corrosion behavior of carbon steel were investigated in order to recommend an appropriate test solution for mildly sour HIC evaluation in a specified pH condition. The remarkable pH shift during a long term HIC test was observed by using 0.05N acetate buffer solution, even though an appropriate balance gas and a large specific solution volume were selected. In contrast, 0.93N acetate buffer solution showed excellent pH stability during long term HIC tests even in low pH and low H2S partial pressure conditions regardless of balance gas selection and specific solution volume. The pH stability can contribute to stable hydrogen entry to the material and the correct HIC evaluation. Therefore, from the viewpoints of convenience and effectiveness for evaluating the resistance of steels to HIC in a specified pH condition, an acetate buffer solution including high total amount of acetic acid and sodium acetate is desirable.