AMPP Store - Products tagged with 'iron sulfide'

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51318-11538-Scaling-resistant coatings for high temperature sour gas service

Product Number: 51318-11538-SG

Author: Lawrence Kool / Hui Zhu / Qilang Wang / Fakuen Chang

Publication Date: 2018

$20.00

This paper describes the development of novel coating materials and methods and evaluation of their effectiveness in preventing iron sulfide scale.

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Chelating Agents for Iron Sulfide Scale Removal at 300°F (149°C)

Product Number: 51320-14859-SG

Author: Raja Ramanathan , Hisham A. Nasr-El-Din

Publication Date: 2020

$20.00

Iron sulfide scales create well deliverability and integrity problems such as reduced production rates and damage to well tubulars. Chelating agents have scarcely been studied for iron-sulfide dissolution. This paper evaluates EDTA, DTPA, and HEDTA for its iron sulfide (FeS) dissolution capacity and kinetics at 300°F (149°C).

A comparative study of the chelating agents with a low pH (3-5), moderate pH (5-9), and high pH (9-14) determined the optimum pH for the scale treatment. These tests were conducted in glass bottles and a high-temperature autoclave apparatus under anoxic conditions. Results show that the iron-sulfide dissolution increases tremendously at 300°F (149°C) when using chelating agents with a pH>5. At 300°F (149°C), the bond strength is reduced, allowing the chelating agents to remove the metal ion from the solid surface. The ranking of the chelating agents in terms of iron-sulfide scale dissolution capacity and effectiveness was DTPA>EDTA>HEDTA at all pH conditions. The role of chelating agents in iron sulfide dissolution at 300°F (149°C) has not been thoroughly investigated. There is no study that reports the optimum treatment time at that temperature. This paper investigates chelating agents and provides the optimum dissolver composition and treatment time for field operations at high temperature conditions.

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Corrosion and Corrosion Products in a Sour Environment from 80°C to 200°C

Product Number: 51317--9084-SG

ISBN: 9084 2017 CP

Author: Shujun Gao

Publication Date: 2017

$20.00

Corrosion rate of mild steel and character of corrosion products in sour environments at temperatures from 20 to 200°C. H2S-H2O water chemistry model was developed. Then, H2S corrosion tests were done at 80, 120, 160 & 200°C - exposure time of 4 days.

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Critical Review on Sulphide Scale Formation, Removal and Inhibition

Product Number: 51320-14731-SG

Author: Bader Al-Harbi, Norah Aljeaban, Alexander Graham, Ken Sorbie

Publication Date: 2020

$20.00

Sulphide scales, namely iron sulphide (FeS), zinc sulphide (ZnS) and lead sulphide (PbS), are increasingly being encountered in gas/oil wells. These scales can present serious safety concerns, impair well productivity and limit access to downhole tools. There are many published research studies addressing sulphide scale removal and inhibition. However, there is an incomplete understanding of the governing processes of sulphide scale formation and prevention. Furthermore, there are contradictory results in the literature on issues such as the removal procedures and inhibition tests for sulphide scales. Therefore, the main objective of this paper is to critically review the published work on sulphide scale formation, removal and inhibition, to address the factors that control them and to discuss some of the apparent discrepancies in published experimental studies.
The review discusses the formation mechanisms of different sulphide scales in relation to the sources and levels of Fe, Zn, Pb and the sulphide species. The experimental procedures used by different researchers to evaluate sulphide scale dissolvers and inhibitors are described, along with the performance results for the chemistries tested to remove or prevent sulphide scales.
Hydrochloric acid has been shown to outperform rival chemistries for dissolving sulphide scales, however the associated high corrosion rate and H2S generation has necessitated the development of other dissolvers to overcome such drawbacks. Several dissolvers based on chelating agent chemistries combined with catalysts provided high dissolution rates, and the dissolution results and the reaction mechanisms will be discussed in some detail.

Multiple factors have been shown to play a significant role in the inhibition efficiency of sulphide scale inhibitors including pH, salinity, temperature, scale formation sequence and mechanism, and the initial concentrations of sulphide species and scaling metals. In addition, there is a developing understanding of the significance of scale inhibitor consumption in these systems.
Understanding the formation mechanism is essential for accurate interpretation of scale-related issues in the field and for providing the correct treatment strategy. A more complete knowledge of these issues will lead to the further development of reliable procedures for generating dissolution and inhibition results and consequently improving the scale dissolver and inhibitor chemistries themselves.

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Evaluation of a Hydrophobic Coating Material for Downhole Application, Lab vs. Field Evaluation

Product Number: 51324-20756-SG

Author: Tao Chen; Feng Liang; Frank Chang; Qiwei Wang

Publication Date: 2024

$40.00

A hydrophobic electroless nickel-phosphorus (ENP) coating material has been developed to reduce corrosion-induced iron sulfide scale deposition. The ENP coating has several key advantages to provide corrosion resistance for sour oil and gas applications, including a level of phosphorus imparting superior corrosion resistance in a sour gas environment, a tailored phosphorus level providing a range of super hydrophobic microstructures, and a second material introduced and embedded in the ENP coating during the coating process to impart desired properties such as wear and erosion resistance. The coating material has been qualified through a series of evaluation tests carried out in the lab, including iron sulfide scale formation under HTHP, coating adhesion tests, explosive decomposition, formation of heazlewoodite (Ni3S2), etc. The coating material was installed in downhole completion tubing through a downhole corrosion and scale monitoring (DCSM) tool to monitor coating stability, corrosion, and scaling under real downhole flow conditions in a sour gas well over 3 months. Overall, the field testing has demonstrated that this newly developed coating material can effectively protect the metal coupon against corrosion and iron sulfide deposition. However, the abrasion of the formed surface layer of Ni3S2 and blistering might be a concern for a long-term field application. This paper will comprehensively compare the coating performance evaluated in the lab and field conditions. Long-term evaluation under real field conditions is highly recommended to qualify the coating material for large-scale application in the downhole.

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Experimental Studies on the Stability of Highly Sour Corrosion Product Layers

Product Number: 51324-21028-SG

Author: Jon Kvarekvål ; Morten Tjelta

Publication Date: 2024

$40.00

The formation and long-term stability of corrosion product layers formed under sour service conditions with up to 30 bar H2S and 10 bar CO2 have been studied. Corrosion experiments were carried out in autoclaves with exposure times up to six months. The test solutions consisted of different brines with sodium chloride concentrations ranging from 0.1 g/L to 100 g/L. Temperatures were in the range of 15-120 oC. Both weight loss corrosion and localized corrosion data were obtained. 3D profilometry was used to obtain detailed data on pitting and localized corrosion morphology. The effects of the corrosion product layers, predominantly iron sulfides, on general and localized corrosion behavior are discussed on the background of existing literature.

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Fe3O4, FeCO3 or FeS - Which Corrosion Product Will Prevail at High Temperature in CO2/H2S Environments?

Product Number: 51320-14413-SG

Author: Shujun Gao, Bruce Brown, David Young, Srdjan Nesic, Marc Singer

Publication Date: 2020

$20.00

Sweet (CO2) and sour (H2S) corrosion have continuously been a challenge in oil and gas production and transportation. Yet, some key issues are still not well understood, especially at high temperature production conditions. A CO2/H2S ratio of 500, which has been used (often inaccurately) to determine which corrosion mechanism is dominant, is probably even less valid at high temperature. The nature of the corrosion products forming at high temperature in CO2/H2S environments and their effects on the corrosion rate are not known. Finally, the impact on pipeline integrity of environmental changes between sweet and sour production conditions (simulating reservoir souring) has not been well documented. CO2, H2S, and CO2/H2S corrosion experiments were conducted at 120oC to investigate corrosion mechanisms and corrosion product layer formation at high temperature. The results show that the corrosion products were still clearly dominated by H2S under the pCO2/pH2S ratio of 550. Formation of Fe3O4, FeCO3, and FeS corrosion product layers had a direct impact on the measured corrosion rates and was dependent on the gas composition and on the sequence of exposure (CO2 then H2S and vice versa). Compared with H2S corrosion alone, the presence of CO2 could retard Fe3O4 formation in CO2/H2S mixture environment. No obvious change in steady state corrosion rate was observed when the corrosion environment was switched from CO2 to H2S and vice versa.

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Field Guide for Managing Iron Sulfide (Black Powder) within Pipelines or Processing Equipment (e-book)

Product Number: 37642-E

ISBN: 978-1-57590-383-5

Author: Daniel E. Powell, Robert H. Winters, Mark A. Mercer

Publication Date: 2019

$190.00

The “Field Guide for Managing Iron Sulfide (Black Powder) within Pipelines or Processing Equipment” offers practical guidance for corrosion control and operations personnel in managing black powder within their pipeline systems or processing equipment. It starts with a discussion of what is black powder and identifies health and safety considerations associated with H₂S and the presence of black powder, identifying why there may be a concern. The Field Guide presents field and laboratory tests typically used to identify the presence of iron sulfide, and then discusses maintenance pigging and/or chemical treatments for removing such particulates. Several case studies are also presented.

2019 NACE E-Book

Field Guide for Black Powder White Paper

Download the free white paper summary of this title to see specific areas of focus and discussion

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Mitigation of Elemental Sulfur and Iron Sulfide Under-Deposit Corrosion

Product Number: 51323-19423-SG

Author: Sherman Kung, Nolan Miller, Feras EI Yaakobi, Jeremy Moloney

Publication Date: 2023

$20.00

Production of highly sour oil and gas fields has increased recently, which introduces new challenges for
corrosion control. In recent years, some unexpected and unexplained pipeline failures have occurred,
resulting in complex investigations and laboratory corrosion performance testing studies to assess the
inhibitors that are applied in these environments. While some of these failures are due to cracking in
sour environments which are prevented by alternative material selection or different operation pipeline
maintenance, we were specifically looking at cases where chemical inhibitors could be used to mitigate
corrosion.

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New Approach on Iron Sulfide Scale Modeling and Prediction at pH 4-7

Product Number: 51320-14532-SG

Author: Xin Wang, Saebom Ko, Alex Yi-Tsung Lu, Guannan Deng, Yue Zhao, Chong Dai, Samridhdi Paudyal, Amy T. Kan, Mason B. Tomson

Publication Date: 2020

$20.00

In this study, a plug flow reactor was built to investigate iron sulfide scale precipitation at various temperatures, pH and ionic strength conditions and two pieces of carbon steel C1018 coupons were put inside as reaction surfaces. The ferrous ion and total sulfide in collected effluent samples were measured to determine precipitation kinetics and solubility. The solid that formed on the steel surfaces were analyzed by Scanning Electron Microscopy (SEM/EDS) and X-ray Diffraction (XRD). The solubility data from this study and literature were collected and fitted by Matlab to build up a reliable FeS solubility prediction model. The experimental results show that mackinawite is the predominant precipitated scale and could be stable for a week at pH higher than 6.0. Iron sulfide precipitation is under diffusion control, accelerated by high temperature and ionic strength. At pH 6 – 7, the aqueous phase neutral species, such as 𝐹𝑒𝑆0𝑎𝑞, plays an important role in the solubility and precipitation kinetic. Based on this study, a new solubility model that combines Pitzer theory and ion-complexes (speciation of ferrous ion) has been developed for iron sulfide solubility calculation and scale prediction.

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Remediation of Microbially Contaminated Horizontal Wells with Acrolein

Product Number: 51320-14992-SG

Author: Jodi B. Wrangham, Adam Bounds, Jerry L. Conaway, Jim Ott, Mason Long, and Corey Stevens

Publication Date: 2020

$20.00

The lengthy laterals of horizontal wells often pose microbiological challenges, as they provide more area to become microbially contaminated and require larger volumes of fluid and biocide for treatment. A Permian Basin oilfield has been experiencing MIC-related failures in its horizontal wells, which is of concern due to the associated high workover cost.

Laboratory biocide challenge testing identified several common oilfield chemistries and combinations thereof as being effective against this field’s population of microbes. However, aggressive applications of these products in the field neither delivered an effective microbial kill nor prevented the treated wells from experiencing further MIC and failures.

An acrolein field trial was conducted on a set of problematic, microbially contaminated horizontal wells over a time period of approximately one year. During this timeframe, these wells experienced microbial control for the first time, defined as meeting and maintaining microbial KPIs. Additional benefits were realized as a result of acrolein, including a dramatic improvement in water quality evident as a decrease in iron sulfide and suspended solids, a clean-out of the wells inferred by an initial increase of solids post-acrolein, a decrease in the corrosion rate as indicated by a significant reduction in iron and manganese counts, a decrease in the well failure rate, an increase in production, and an overall cost savings associated with the application of acrolein.

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Shale Gas Production Pipeline Failure - Case Study

Product Number: 51324-20698-SG

Author: Feras El Yaakobi; Sherman Kung; Connor Graham; Jeannine Schmid; Daryl Foley

Publication Date: 2024

$40.00

Shale gas production is unique and presents challenges in terms of corrosion mitigation and pipeline integrity management. Many of these challenges stem from variations in production modes from the early stages and as the system becomes mature, with many variables involved such as frac flowback, H2S, CO2, iron, microbial, velocities, topography, O2, hydrates, and paraffin. When combined with economic challenges the oil and gas industry faces, these factors force producers to strike a balance between technical decisions and operational/cost efficiencies, which adds complexity to an already difficult-to-manage system. This paper will review a pipeline failure case study from a critical sour shale gas gathering system in Canada. The case study will cover the history of the pipeline from commissioning until failure, challenges faced, root-cause analysis, solutions implemented, and results obtained. The case study will help increase awareness about best practices regarding pipeline pigging, corrosion inhibitor batch treatments, and analytical testing used when conducting failure root cause analysis. It also serves as a documentation for a corrosion failure in a pipeline with a staggering corrosion rate of over 2,800 mpy resulting in a pipeline failure in less than five weeks of operations.

Products tagged with 'iron sulfide'

Association for Materials Protection and Performance