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Collaborating Authors
Brown, Bruce
Abstract In laboratory experiments, corrosion of mild steel specimen in glass cells or autoclaves with a relatively small internal volume (of the order of 1 liter or less), will usually lead to a change in solution chemistry, (i.e., increase in ferrous ion concentration and solution pH) which will affect the corrosion product formation and ultimately the corrosion rate. However, in much larger field systems that are being simulated in the laboratory, such as for example oil and gas mild steel pipelines, the solution chemistry at any specific location does not change significantly over the same time period, since it is governed by the flow coming from further upstream. Therefore, it is very important to be able to maintain a stable solution chemistry in small scale laboratory experiments, in order to get a better simulation of corrosion seen in the field. In this work, a stable solution chemistry system was developed using ion exchange resins. H-form and K-form exchange resins were successfully tested in long term experiments aiming to keep pH and ferrous ion concentration reasonably stable. The results show that pH can be controlled within ±0.02 pH units and ferrous ion concentration within ±3 ppm. The results of electrochemical measurements and surface analysis show that there is a significant difference in both corrosion rate and corrosion product layer formation when a stable solution chemistry system is used. Introduction In small scale constant inventory laboratory experiments, CO2 corrosion of mild steel will often lead to a change in aqueous solution chemistry (i.e. increase in ferrous ion concentration and solution pH). As an example, Figure 1 shows the changes in ferrous ion concentration and solution pH during a small scale lab experiment with an API 5L X65 specimen with surface area of 5.4 cm2 in 2 liters of CO2 purged, 1 wt.% NaCl solution at 40 °C and initial pH 4.0. It was found that ferrous ion concentration increased from 0 to 54 ppm during 72 hours. At the same time, the solution pH increased more than 1 pH unit, from pH 4.0 up to pH 5.1. However, for a field system,¹ such as an oil or gas pipeline, the solution chemistry at a any given location inside the line does not change significantly over time, as there is always fluid flow coming from upstream. It is well known that the increase in pH and ferrous ion concentration will affect the CO2 corrosion rate and the precipitation rate of corrosion products such as iron carbonate. Therefore, it is not trivial to conduct and interpret corrosion results from small scale lab experiments that are meant to simulate field corrosion data.
Abstract Localized corrosion in sour fields is a challenge persisting in the oil and gas industry since it has frequently been seen as a cause for catastrophic failures of upstream pipelines. Hence, prediction and mitigation of H2S localized corrosion of mild steel is of key importance for integrity management. However, our current understanding of H2S localized corrosion mechanism(s) from numerous studies in both in the laboratory and the field is far from being conclusive. Especially, the environmental conditions that may cause localized H2S corrosion are unclear. Therefore, defining an experimental condition in the laboratory that can replicate localized corrosion in a sour environment is critical to our understanding of mechanisms of localized corrosion. The focus of the present research was to explore environmental conditions leading to localized H2S corrosion. It was found that severe localized corrosion was repeatedly observed in experiments, when there was a simultaneous formation of greigite and/or pyrite. Based on those experimental results, a hypothesis for a mechanism of H2S localized corrosion was proposed. Introduction Corrosion caused by the presence of H2S and CO2 in produced fluids is frequently encountered in pipelines during the production of oil and gas. Compared to general CO2 and H2S corrosion, localized H2S corrosion is much less understood and less studied. This poses a key challenge for integrity management in the oil and gas industry. In open literature, H2S localized corrosion has been usually associated with multiple risk factors, such as the presence of elemental sulfur, the presence of polysulfides, high salinity, flow velocity, a change in local water chemistry at steel surface16, and metallurgy. In addition, corrosion and scaling mitigation strategies, such as corrosion inhibitors, alcohol and glycols, and pH stabilization, used in sour systems in the oil and gas industry, can greatly decrease the uniform corrosion, while increasing the probability for localized corrosion. Kvarekval et al. have showed very strong evidence of this with examples of severe localized corrosion.
- Asia (1.00)
- North America > United States > Texas > Harris County > Houston (0.16)
Abstract The internal corrosion of pipeline steel in the presence of hydrogen sulfide (H2S) represents a significant problem in oil and gas industry. Its prediction and control pose a challenge for the corrosion engineers. In previously published research by the same authors, an electrochemical model of H2S corrosion was developed in both pure H2S and H2S/CO2 aqueous systems. An additional electrochemical cathodic reaction, direct H2S reduction, was uncovered based upon the carbon steel corrosion experimental results. However, in the carbon steel corrosion experiments, the cathodic sweeps experienced interference by the anodic iron dissolution reaction, making the kinetics of cathodic reactions unclear. In the present study, experimentation was conducted to better resolve the direct reduction of H2S while minimizing the effect of the anodic reaction by using a passive stainless steel working electrode. The electrochemical kinetics parameters for H2S reduction (i.e. Tafel slope, exchange current density, and reaction order with H2S concentration) were determined. Moreover, the electrochemical kinetics parameters for H reduction were also revisited. >Introduction The internal corrosion of pipeline steel in the presence of hydrogen sulfide (H2S) represents a significant problem in oil and gas industry. Its prediction and control pose a challenge for the corrosion community. The aqueous H2S corrosion of carbon steel is an electrochemical process occurring at the steel surface. The overall reaction is dependent on the kinetics of different electrochemical reactions, which are composed of two simultaneous electrochemical half-reactions: anodic (oxidation) and cathodic (reduction). The present study is focused on cathodic reactions in H2S corrosion of carbon steel. The best known cathodic reaction in aqueous solution is hydrogen evolution or hydrogen ion (H) reduction, Reaction (1), which has been intensely investigated in strong acid solutions with different substrates. The same kinetics has been assumed to hold in both CO2 and H2S corrosion models.
- Asia (1.00)
- North America > United States > Texas > Harris County > Houston (0.16)
- Materials > Metals & Mining > Steel (1.00)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government (0.93)
Abstract In aqueous carbon dioxide (CO2) solutions where both Ca and ferrous iron (Fe) are present, such as downhole gas reservoirs or deep saline aquifers after CO2 injection, mixed metal carbonates with the formula FexCayCO3 (x+y=1) can form. This inhomogeneity may lead to localized corrosion. During carbon steel corrosion experiments conducted in electrolytes containing high Ca concentrations, inhomogeneous corrosion product layers with the composition FexCayCO3 (x+y=1) were indeed observed, along with non-uniform corrosion. Determining relative molar fractions of Ca and Fe in FexCayCO3 is paramount to predicting the relative properties and stability of such mixed metal carbonates. Using Bragg’s Law and equations to relate inter-planar spacings to unit cell parameters, Xray diffraction (XRD) data yielded values for the molar fraction of Ca in FexCayCO3. Procedures in the current experimental study were designed to develop a range of specific corrosion product layers on mild steel samples. Experiments were conducted at constant Cl- concentration with and without 10,000 ppm Ca in stagnant conditions, for two different flow conditions. In stagnant conditions, localized corrosion was associated with the presence of Ca and the inhomogeneity of the corrosion product layer. The corrosion attack became uniform when flow was introduced. Introduction The effect of calcium cations (Ca) on the formation and protectiveness of iron carbonate (FeCO3) layers in aqueous carbon dioxide (CO2) corrosion of mild steel was discussed in a previous study. It showed that the isostructurality of calcium carbonate (CaCO3) and FeCO3 allowed the incorporation of Ca into the FeCO3 structure; thus, the morphology and chemical properties of FeCO3 were altered. The importance of FeCO3 formation on corrosion protection of mild steel has been well documented. In a stagnant aqueous CO2 solution, the water chemistry at the corroding steel surface is not the same as the bulk water chemistry. As a consequence of the corrosion process that consumes hydrogen (H) and releases ferrous iron (Fe) to the solution, the pH and Fe concentration increase adjacent to the steel surface. This leads to a higher degree of FeCO3 saturation near the steel surface and a higher probability of protective FeCO3 layer formation. However, in a turbulent well-mixed solution a corroding bare steel surface has almost the same water chemistry as the bulk solution, making protective FeCO3 layer formation less probable. In addition, at very high flow rates, there is a possibility of removal of protective FeCO3 layers, leading to localized corrosion.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
Abstract Mitigation of localized under deposit corrosion (UDC) in upstream oil and gas pipelines is an important research topic for both industry and academia. In a research program focused on understanding various inhibitor components that provide mitigation of UDC, initial research investigated the effect of varied ratios of mono- to dinonylphenol phosphate esters (PE) by testing a set of specifically formulated inhibitors. Inhibitors with three mono- to di- PE ratios were tested in the presence and absence of 2-mercaptoethanol (ME). Using two 1.25 in. (3.18 cm) diameter API 5L X65 pipeline steel samples and 250 µm silica sand, UDC testing was conducted for 28 days in a CO2 saturated solution at 70°C and 1 bar total pressure. Analysis has shown that localized corrosion (pit penetration rate) increased for ME-free nonylphenol PE as the concentrations of di-PEs and mono-PEs approached equivalency. The nonylphenol PE inhibitor with a 50:50 mono- to di- PE ratio at 100 ppm concentration failed to protect the surface of the sample under the individual sand grains. Even the base product inhibitor package with no PE provided better mitigation under these test conditions than the 50:50 mono- to dinonylphenol PE. However, it was observed that the addition of ME provided a dramatic improvement in the mitigation of UDC for each mono- to di- PE ratio of the nonylphenol PE tested. From this research, it is seen that the mono- to di- phosphate ester ratio is important to consider when developing corrosion inhibitors containing phosphate esters. Introduction UDC is a localized corrosion that occurs where sediments, carried through a production or transmission pipeline, have settled in stagnant or low-flow sections of a pipeline and mitigation strategies have been ineffective or impractical. When the flow is low enough and silica sand collects on the bottom of the pipeline, the sand deposit can retard uniform corrosion of mild steel by slowing down the mass transfer of corrosive species. When an inhibitor has been introduced to mitigate corrosion, it has been thought that the sand deposit can act to slow down inhibitor diffusion to the metal surface and may deplete the inhibitor concentration through adsorption on the large surface area of the sand. However, these mechanisms are not considered to be the critical factors leading to localized corrosion in under-deposit CO2 corrosion, although localized corrosion is documented to occur. In one published example, general corrosion rates in a crude oil transmission pipeline were measured in the range of 0.2 to 0.4 mpy (0.005 to 0.01 mm/yr), but significant localized pitting was found under the sediment in the bottom of the line.¹
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
Using Wired Drill Pipe, High-Speed Downhole Data, and Closed Loop Drilling Automation Technology to Drive Performance Improvement Across Multiple Wells in the Bakken
Trichel, Donald K. (Hess Corp.) | Isbell, Matthew (Hess Corp.) | Brown, Bruce (BD Drilling Consultants LLC) | Flash, Major (National Oilwell Varco) | McRay, Michael (National Oilwell Varco) | Nieto, James (National Oilwell Varco) | Fonseca, Isaac (National Oilwell Varco)
Abstract Many operators have developed optimization processes to reduce well delivery time and cost. These optimization processes typically include three basic performance improvement cycles: The first, the Real-time cycle, involves the management of drilling parameters to safely maximize penetration rate and drill bit run length with the drilling system currently in the hole. This cycle moves at a fast pace. The second, the Run-to-Run cycle, involves recognizing and reacting to the drilling system configuration needs based on performance during the run. These adjustments can only be applied to the following bit run or the same interval on a future well. This cycle moves at a slower pace than the first. The third, the Well-to-Well cycle, uses a detailed post-well analysis of performance trends and massive amounts of digital data collected over multiple wells to identify root causes of performance limiters. This knowledge is then applied to the drilling system re-design. This cycle is the slowest of the three. To accelerate learning, the operator deployed a real-time, closed loop, downhole automation system (DHAS) in conjunction with wired drill pipe in the 8 ¾ in. hole section. The operator also used downhole memory tools in the 5 7/8 in. lateral section to collect downhole drilling parameters and vibration data. Our optimization process drew upon key elements from lean manufacturing concepts. It followed a Plan, Do, Check, Adjust (PDCA) loop, with the DHAS and the data provided by it impacting each of the three concurrently moving performance improvement cycles. The pilot test of the DHAS in the Bakken continued for 16 wells on four different surface locations, or pads. Thirteen out of sixteen 8 ¾ in. hole intervals drilled with this system exhibited top quartile performance from a rig that had not drilled a top quartile well for over 2 years. As many as 45 hours of invisible lost time were removed from on-bottom drilling in a single hole section, compared to average performance in the same interval for the last three pads drilled with this same rig. Additionally, the operator identified previously unrecognized rate of penetration (ROP) limiters over the course of the project. The key limiter for the 8 ¾ in. vertical interval was a directional dropping tendency of the bottomhole assembly (BHA) which also limited the ability to mitigate the second key limiter, drill bit vibration. Off-bottom practices (e.g., reaming) limited performance for the curve interval. The key limiter for the lateral turned out to be tool failures, resulting from vibration events occurring during on-bottom and off-bottom transitions. The drilling team also learned how each of the performance improvement cycles is affected by the DHAS.
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
ABSTRACT Over the past decade, the knowledge related to predicting internal pipeline corrosion for sweet and particularly sour environments has dramatically improved. The latest model of uniform CO₂/H₂S corrosion of carbon steel accounts for the key processes underlying of corrosion: chemical reactions in the bulk solution, electrochemical reactions at the steel surface, the mass transport between the bulk solution to the steel surface, and the corrosion product formation and growth (iron carbonate and iron sulfide). The model is able to predict the corrosion rate as well as the surface water chemistry as related to all the key species involved. The model has been successfully calibrated against experimental data in conditions where corrosion product layer do not form and in environments where they do, and compared to other similar models. INTRODUCTION Corrosion predictive models are a very useful tool that can be used to determine corrosion allowances, make predictions of facilities remaining life, and provide guidance in corrosion management. When it comes to internal corrosion of mild steel in the oil and gas industry, the mechanism of CO₂ corrosion is well understood through laboratory investigations. Hence, models for CO₂ corrosion developed in the past, range from those based on empirical correlations to mechanistic models describing the different processes involved in CO₂ corrosion of carbon steel.
ABSTRACT Understanding the mechanisms that lead to localized corrosion in oil and gas pipeline is of great interest to corrosion engineers worldwide. Observations of localized corrosion that occurred in slightly sour conditions in a large scale flow loop under single phase and multiphase flow were used to develop a better understanding of how bulk solution conditions can affect the growth of the corrosion product layers, over time, and their relationship to localized corrosion. It was shown that the solution bulk pH, ionic strength, and concentrations of carbonate and sulfide species are the major factors related to development of localized corrosion in a slightly sour environment. The experimental data was then analyzed and used to develop a correlation to relate these parameters to the likelihood of localized corrosion. Key words: localized corrosion, sour corrosion, pitting, hydrogen sulfide, carbon dioxide, iron sulfide, iron carbonate, ionic strength, pitting ratio, pH, chloride INTRODUCTION Localized corrosion in its most extreme form is defined as a non-uniform loss of metal from the internal pipe wall of an upstream oil and gas pipeline which leads to a loss of containment. Pipelines designed to withstand 50 years of operation under the worst case general corrosion rate may fail after a few months of operation due to localized corrosion. Loss of containment from a pipeline failure is a costly event as it would cause an emergency shutdown in the production of oil and/or gas, an emergency repair of the pipeline, and probably an environmental clean-up at the leak site.
- Asia (0.46)
- North America > United States > Texas (0.17)
Abstract CO2 corrosion has been recognized as a major problem in internal pipeline corrosion. In the presence of water, CO2 forms carbonic acid, a weak acid which partially dissociates as a function of pH and the solution temperature. According to many studies, the presence of CO2 and therefore, carbonic acid enhances the corrosion rate of mild steel by accelerating the cathodic reaction. The exact mechanism of carbonic acid reduction at the metal surface is still being debated. When the reduction of the adsorbed carbonic acid molecule occurs at the metal surface, the mechanism is called "direct reduction", originally proposed by deWaard and Milliams in 1975. An alternative explanation has carbonic acid providing additional hydrogen ions via its dissociation while the dominant cathodic reaction is reduction of hydrogen ions; this mechanism is referred to as a "buffering effect". In the present study, electrochemical techniques such as linear polarization resistance (LPR), potentiodynamic sweeps and electrochemical impedance spectroscopy (EIS) were used in order resolve this dilemma, i.e. to investigate the exact mechanism of the cathodic reaction in the presence of carbonic acid. It was found that carbonic acid affects only the limiting cathodic current, but has no effect on the charge transfer current. The charge transfer current is found to respond only to a change in pH, indicating hydrogen ion reduction as the main cathodic reaction. The buffering effect is therefore considered to be dominant; the direct reduction of carbonic acid appears to be insignificant compared to the reduction of hydrogen ions in the range of conditions covered by this study.
- Asia (1.00)
- North America > United States > Texas > Harris County > Houston (0.16)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government (0.93)
Abstract In the present study, a comprehensive thermodynamic model, depicted by Pourbaix diagrams, has been developed with the relatively narrow focus on corrosion of mild steel in oil and gas field conditions. This thermodynamic model focuses on predicting the formation of metastable or stable corrosion products in sour environments at elevated temperature up to 250 C, which includes mackinawite (FeS), greigite (Fe3S4), the pyrrhotite group (Fe1-xS, x = 0 to 0.17) and pyrite (FeS2). The model is based on theoretical thermodynamic calculations and data collection from open literature. As known, the appearance of Pourbaix diagram is significantly affected by temperature since thermodynamic properties are highly sensitive to temperature. Therefore, specific corrosion experiments at two different temperatures (25 C and 80 C) were designed to compare the predictions of corrosion products made by the Pourbaix diagrams to those formed during experiments. It was observed that the experimental results generally agreed with the predictions made by the Pourbaix diagrams.
- Asia (1.00)
- North America > United States > New Jersey (0.28)
- 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)