AMPP Store - Products tagged with 'h2s'

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AISI 420/410 Modified Martensitic Stainless Steel bar Stock Materials Sulphide Stress Cracking (SSC) Resistance in Mildly Sour Environments

Product Number: 51323-18759-SG

Author: Roberto Morana, Lee Smith, Perry Nice, Lucrezia Scoppio, Marc Müller, Karola Klenke, Roberta Prencipe, Luciana Intiso

Publication Date: 2023

$20.00

Martensitic Stainless Steel (SMSS) is widely used for downhole production tubing and liners in the Oil & Gas industry. Optimization of the tubular material chemistry, cleanliness and manufacturing route has delivered useful performance in H2S-containing environments (specifically SSC and stress corrosion cracking [SCC])3 resistance4,5,6. Some tubular accessories and most completion equipment require sizes not readily delivered by tubular product form. In these instances, bar stock material is a pragmatic choice.

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ANSI/NACE MR0175-HD2000-SG Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment-HD2000

Product Number: 21302-HD2000

Author: NACE International

Publication Date: 2000

$179.00

Metallic material requirements for resistance to sulfide stress cracking (SSC) for petroleum production, drilling, gathering and flowline equipment and field processing facilities to be used in hydrogen sulfide (H2S)-bearing hydrocarbon service. Historical Document 2000

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ANSI/NACE MR0175-HD2003-SG Metals for Sulfide Stress Cracking and Stress Corrosion Cracking Resistance in Sour Oilfield Environments-HD2003

Product Number: 21302-HD2003

ISBN: 1-57590-021-1

Author: NACE International

Publication Date: 2003

$179.00

Metallic material requirements to provide resistance to sulfide stress cracking (SSC) and/or stress corrosion cracking (SCC) for petroleum production, drilling, gathering and flow line equipment in H2S service. Historical document 2003

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Characterizing Properties and Stress Corrosion Cracking Resistance of Alloy 718 via Additive Manufacturing

Product Number: 51323-19117-SG

Author: Karthik Krishnan

Publication Date: 2023

$20.00

UNS N07718 (Alloy 718) is a precipitation-hardened Nickel alloy widely used for various components in oil and gas production service where a combination of high strength, good cracking and corrosion resistance is needed. API 6ACRA provides heat treatment windows and acceptance criteria for wrought Alloy 718 in these oil and gas production environments, in which the heat treatment is intended to obtain high strength desired for applications in combination with good environmental performance.

Additive Manufacturing (AM) is increasingly becoming a source of design, fabrication of complex components where machining from wrought material would be very cumbersome or introduced complicated welding processes.

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Choice of Buffer Solution for Stainless Steel OCTG at Laboratory Corrosion Test to Carry Out SSC and SCC Resistance

Product Number: 51317--9288-SG

ISBN: 9288 2017 CP

Author: Yasuhide Ishiguro

Publication Date: 2017

$20.00

This paper reviews a theoretical background of buffer solutions for stainless steel oil country tubular goods materials at laboratory corrosion test, and then the concept is applied to NACE-TM0177-based solution and modified solutions.

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Comparative Study of FBE Internal Coatings in CO2/H2S/N2-brine/MEG

Product Number: MECC23-20099-SG

Author: Abdulrahman Al-Huwaiji; Turki Al-Khaldi; Zahrah Al-Tarooti; Khalid Al-Mudarra; Anas Al-Rushaid; Haitham Al-Juhani

Publication Date: 2023

$20.00

Fusion Bonded Epoxy (FBE) organic coatings have been widely used in the oil and gas industry for more than 50 years for internal and external pipeline applications, as they have been proven to efficiently provide good pipeline corrosion protection for many years. As demand for oil increases leading oil and gas companies to expand operations and venture into fields and depths more severe than ever before, there is an expectation for FBE coatings to also evolve in order to meet these new corrosion challenges[1]. One main challenge in the selection of FBE coatings, is the qualification of organic coatings that can handle sweet and sour services at high pressures in NaCl and MEG media [2].

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CorrCompilation: CO2 and H2S Metal Loss Corrosion - 10 Year Review (E-book)

Product Number: 37623-E

ISBN: 978-1-57590-350-7

Author: Yves Gunaltun

Publication Date: 2017

$137.00

Mechanism, prediction, monitoring and control of CO2 and H2S metal loss corrosion. Papers that reviewed the subject in 2006 and 2015, with the objective of reorienting research and development. 2017 downloadable NACE E-BOOK

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Corrosion & Mechanical Properties of Nickel Based Alloy 825 Explosion Welded Plates for H2S Service

Product Number: 51323-19123-SG

Author: O. Sarrat, H. Alves, J. Botinha, P. Maas

Publication Date: 2023

$20.00

The total project study focused on six suction and discharge drums. Each of them was built with twohemispherical heads and a number of shells. The H2S service and Stress Corrosion Cracking (SCC) from this specific oil and gas field required the equipment to be cladded with Alloy 825 to protect them from corrosion.

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Corrosion Behavior of UNS N08935 In Refinery Sour Water Services

Product Number: 51321-16831-SG

Author: Karen Picker; Josefin Eidhagen; Jonas Howing

Publication Date: 2021

$20.00

Available for download

Corrosion Inhibitor Film Stability Under High Gas Velocity Conditions of Subsea Wet Gas

Product Number: 51317--9247-SG

ISBN: 9247 2017 CP

Author: Bei Wang

Publication Date: 2017

$20.00

This paper details challenges of high pressure sour gas projects with high salinity and provides cases of field history, explanation regarding material selection framework and technical challenges during the design, execution and operating phases of sour service projects.

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Corrosion Prediction in Perforated Polymer Lined Pipelines (PLP) Used for Oil & Gas Transportation

Product Number: 51324-20954-SG

Author: Gaurav R. Joshi; Remy Mingant; Jean Kittel; Jitender Rai; Carol Taravel-Condat

Publication Date: 2024

$40.00

The perforated polymer-lined pipeline (PLP) is a rigid carbon steel pipeline with internal polymer liner for internal corrosion prevention. The liner is perforated to prevent liner collapse during depressurization. Although the perforations expose the carbon steel to the corrosion fluids within the bore of the pipeline, extensive small-scale and full-scale tests have demonstrated that corrosion at the bottom of each perforation is much less than the corrosion in an un-lined carbon steel pipeline. Based on experience gained on the evaluation and modelling of corrosion in the highly confined environments of flexible pipelines, we have developed a corrosion model to simulate carbon steel corrosion rates corresponding to the perforated PLP system geometry. Predictions from this model could help evaluate corrosion risks at and within perforated liner / steel interfaces. This paper presents an overview of the model and compares its predictions against a variety of experimental data that reproduce the conditions, the geometry, or both, found at the bottom of a PLP perforation. This 1D model considers diffusion and chemical reactions inside an inert hole and incorporates non-ideal thermodynamics (i.e., gas fugacity effects) to describe the aqueous solution chemistry. Electrochemical corrosion equations are compared with experimental data to support validation. This model could serve as a useful tool that complements qualification testing and help validate the PLP technology for a variety of field applications.

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Corrosion Testing of Carbon Steel and 13Cr Casing Materials in Simulated Superhot Deep Geothermal Well Environment

Product Number: 51324-20903-SG

Author: Sigrun Nanna Karlsdottir; Gifty Oppong Boakye; María Ýr Þráinsdóttir; Erlend Straume; Andri Ísak Þórhallsson

Publication Date: 2024

$40.00

Major challenges are encountered in the design and construction of deep superhot (>300°C) geothermal wells due to higher temperatures and pressure, and increased corrosiveness of the geothermal fluid. The corrosiveness of the geothermal fluid is due to the chemical composition which includes corrosive gases such as HCl, H2S and CO2. In this study L80-type 1 carbon steel and L80-13Cr stainless steel API casing materials were tested in a simulated superhot geothermal well environment at 350°C in water with Cl, H2S and CO2 for 168 hrs. in both vapor and liquid phases in high temperature and high pressure (HTHP) autoclave to investigate their corrosion behavior. The results showed that both API casing materials, L80-type 1 and L80-13Cr, were prone to corrosion attack in the simulated superhot deep geothermal well environment. The L80 grade Type 1 carbon steel tested in the liquid phase exhibited the highest corrosion rate and demonstrated vulnerability to localized corrosion or cracking in both liquid and vapor phases. Similarly, the L80 grade 13Cr stainless steel is not considered a suitable choice for harsh environments rich in H2S, CO2, and Cl at superheated temperatures. While it was prone to localized corrosion, it exhibited a low uniform corrosion rate (<0.1 mm/year).

Products tagged with 'h2s'

Association for Materials Protection and Performance