AMPP Store - Products tagged with 'co2'

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51318-11262- Effectiveness Testing on Vapor Phase Corrosion Inhibitors Using Rotating Cage Autoclave and Electrochemical impedance Spectroscopy Methods

Product Number: 51318-11262-SG

Author: Larry Chen / Nihal Obeyesekere / Jonathan Wylde

Publication Date: 2018

$20.00

This paper discusses the product design philosophy for corrosion inhibitors used for CCTS (Carbon Capture, Transportation and Storage), which have to work in both vapor phase and liquid phase at the same time.

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51318-11266-Sour Gas Plant Corrosion in the Presence of Elemental Sulfur

Product Number: 51318-11266-SG

Author: Tracey Jackson / Jason Moses / Don Stegmann

Publication Date: 2018

$20.00

A sour gas plant was experiencing high corrosion and fouling in aggressive conditions (170 to 195°F, 170 psi pH2S, 280 psi pCO2) including the presence of elemental sulfur (0.1 wt%). The current chemical program appeared to be ineffective.

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51318-11268-Room Temperature Gas Charging to Achieve Test Pressures at Temperature

Product Number: 51318-11268-SG

Author: Tracey Jackson / Haitao Fang

Publication Date: 2018

$20.00

In this paper the charging procedure will be demonstrated. Two case histories will be shown including autoclave telemetry data (pressure and temperature) and pressure measurements taken at temperature.

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51318-11477-Corrosion evaluation of tubing steels and material selection in the CO2/H2S coexistent environment

Product Number: 51318-11477-SG

Author: Nai-yan ZHANG / Zhi ZHANG / Wen-tao ZHAO / Lian LIU / Taihe SHI

Publication Date: 2018

$20.00

To evaluate the applicability of the tubing steels, the corrosion behavior and stress corrosion cracking of tubing steels (P110S, P110-13Cr and duplex stainless steel 2205) were investigated under different H2S partial pressures and temperature.

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51318-11481-Impacts of Impurities SO2 and H2S on Corrosion of sc-CO2 Pipe Steels

Product Number: 51318-11481-SG

Author: Yimin Zeng / Kaiyang Li / Jingli Lao / Muhammad Arafin

Publication Date: 2018

$20.00

This paper re-examines most public and in-house corrosion data on the effects of six typical impurities to advance the fundamental understanding of how pipeline steels corrode in sc-CO2 environments and identify knowledge gaps for further investigations.

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51318-11541-Corrosion of Casing Vapor Recovery System in Steam Flooding Operation

Product Number: 51318-11541-SG

Author: Kehinde M. Ogun

Publication Date: 2018

$20.00

Corrosion problems in casing vapor recovery system in a steam recovery processes to optimize corrosion management, considering maintenance, mitigation, inspections, material selection and cost-effective 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 and Cracking Performance of Stainless Steels and Nickel Alloys in CCS Environments

Product Number: 51324-20962-SG

Author: Karthik Krishnan; Cheng Chau Lum; Arpana Verma

Publication Date: 2024

$40.00

Carbon Capture and Storage (CCS) technology which involves capturing CO2 and injecting into geological formations is seen as a focus area for reducing CO2 emissions and sustainable future. One of the key challenges for CCS is material selection for construction of wells for injection and storage where the materials can be subjected to a complex environmental mix with various impurities present in the CO2 stream along with different phases within the well. Knowledge and understanding of corrosion and cracking performance of various materials in different environmental conditions relevant to CCS wells can provide a basis for material selection. Being a relatively new field there is an effort to build up knowledge base via testing, characterizing materials suitable for long term well service. In this study, martensitic, supermartensitic and super duplex stainless steels along with Age Hardenable (AH) Nickel Alloy were tested for both corrosion and cracking performance in different CCS type environments. The testing simulated exposure to injected fluid phase, interface between injected fluid and water phase and completely immersed in water phase. The details of testing performed results obtained along with discussions is presented so that it can provide guidance on material compatibility for some of the CCS environments.

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Corrosion Inhibitor Selection for High Temperature Sweet Gas Wells

Product Number: MECC23-20111-SG

Author: Anas S. Rushaid; Ali A. Jabran; Hassan A. Ajwad; Waleed A. Ghamdi

Publication Date: 2023

$20.00

CO2 is well recognized to be a major factor accelerating the corrosion process. When CO2 dissolves in water, it forms carbonic acid which is a weak acid and it dissociates only slightly to form bicarbonate ion followed by further dissociation to form carbonate ions (Figure 1). At pH levels lower than 5.5, the bicarbonate ions (HCO3-) are the main carbonic species in solution.

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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 'co2'

Association for Materials Protection and Performance