One of the primary drawbacks of using electronic sensors for continuous corrosion monitoring in remote locations is the need to provide power and communications at the test location. The present work explores the use of a low-power wireless sensor network to overcome these challenges. Such a network allows sensors to be powered by locally installed energy harvesting elements (i.e., thermoelectric, solar). The communication protocol of the wireless sensor network permits each node to communicate with every other node and store (back-up) data for the entire network. The result is a robust and easily deployable network of sensors that spans large distances. The current effort focuses on the development of conductivity probes that are compatible with industry-standard internal corrosion monitoring infrastructure (i.e., access fittings, coupon holders) and amenable to integration into a low-power wireless sensor network. 

This paper introduces an innovative approach for mitigating hydrogen embrittlement in materials used in underwater environments, a critical challenge in marine engineering. Our study focuses on developing a comprehensive 'master curve' that encapsulates the complex interplay among key factors: hydrogen concentration, applied potential, and material strength. This curve serves as a predictive tool for evaluating the susceptibility of materials to hydrogen embrittlement, a phenomenon that lacks a one-size-fits-all solution. Through fracture mechanics testing of carbon steel alloys and rigorous analysis, quantitative relationships between these factors are established. This research not only aids in optimizing material selection and designing effective cathodic protection systems but also ensures enhanced safety and integrity in operational contexts. The master curve, rooted in both empirical data and theoretical insights, offers a strategic framework for engineers and industry professionals, guiding decisions that enhance the durability and reliability of subsea equipment.

In High Pressure High Temperature “HPHT” wells (pressure above 10000psi/690bar temperature above 300°F/150°C which contain CO2 (sweet corrosion) and H2S (sour service) the oil & gas operators need to select materials which are resistant in corrosive atmosphere during the well lifetime. At the same time high strength grades are usually required to meet collapse and burst properties. The aim of the end users is to get the specific grade which can resist to corrosion while minimizing the cost which involves qualification with corrosion tests.The API 5CRA standard defines corrosion resistant alloy (CRA) grades for casings and tubings from group 1 named “Super 13Cr 13-5-2” (suitable up to 356°F/180°C) to group 2 “Duplex” grades 22-5-3 (450°F/232°C) or “Super Duplex” 25-7-4 (482°F/250°C) and higher grades.Therefore when the well temperature is above 356°F/180°C duplex grades or higher are commonly selected as these materials have a larger application domain at higher temperature range.A new proprietary grade chemistry was developed to provide good corrosion performances up to 230°C 125ksi (862MPa) grade material and high impact toughness. From a metallurgical standpoint achieving targeted mechanical and corrosion performances has ended up in a multi-phases material (martensite delta ferrite and austenite). Most of the performances are mainly controlled by the phases balance which alloy optimization has enabled consistent control by heat treatment.Stress corrosion cracking performances were assessed and compared to Super 13Cr and Super Duplex materials showing significant benefice of chromium under high temperature. Potentiodynamic electrochemical measurements in H2S environment were performed at 24°C in order to evaluate pitting performance and assess risk of sulfide stress corrosion cracking confirming higher sulfide stress corrosion performance compared to S13Cr materials. X-ray Photoelectron Spectroscopy (XPS) characterizations provide deep knowledge about it passive film compositions underlining the beneficial effect of high chromium within the grade.This solution offers to Oil and Gas operators a cost effective designed seamless tubes for high temperature well reservoir condition as alternative to duplex materials.

High nitrogen FeCrMn -austenitic stainless steels are used in oil and gas applications such as non-magnetic drill collars, Measuring While Drilling (MWD), and Logging While Drilling (LWD) housings. These steels are characterized by a good combination of high strength and high corrosion resistance in aggressive environments. This paper presents some results of a newly developed non-magnetic high interstitial (FeCrMnMo(C+N)) austenitic stainless steel which shows high strength, toughness, and enhanced corrosion properties. Characterization of microstructure, mechanical and corrosion properties was performed. After solution annealing at 1125 °C, the new 18Cr-18Mn-2Mo-1(C+N) is fully austenitic without precipitates or δ-ferrite. The newly developed stainless steel is characterized by an elongation higher than 60 %, a yield and ultimate strength of 600 MPa and 980 MPa, respectively, combined with high impact energy (≥ 350 J). Pitting resistance equivalent number (PREN) is > 35. The high-interstitial (HI) steel shows no intergranular corrosion without sensitization treatment (ASTM A262) and no weight loss in ferric chloride solution testing at room temperature for 72 hours (ASTM G48 Method A). The critical pitting temperature tested in acidified ferric chloride is 35 °C (ASTM G48 Method E). The new high interstitial FeCrMn austenitic stainless steel is a very promising grade for applications in the oil and gas industry due to the high mechanical strength above 1000 MPa combined with good corrosion properties. 

The presence of dissolved oxygen in boiler feed water and steam generating systems can present serious problems in a steam generating plant by promoting corrosion and thick scale formation in the feed water system the boiler and the steam condensate system. Therefore it is important to remove oxygen from the feed water and also from the condensate where in-leakage can occur. The first step in the elimination of oxygen from the boiler feed water is mechanical deaeration. The second step involves chemical oxygen scavenging to remove the residual oxygen. Hydrazine is used as an oxygen scavenger to control corrosion in steam generating systems despite being a genotoxic carcinogen. Alternative chemicals nontoxic corrosion inhibitors or new oxygen scavenger-free water treatment technologies are preferred. A newly developed amine based vapor phase corrosion inhibitor was investigated. Electrochemical tests were conducted and showed a significantly lower corrosion rate in boiling water. Short term corrosion tests in boiling water showed a decreased corrosion rate from 5.3 mpy to 1.93 mpy for 50 ppm VCI and 1.32 mpy for 100 ppm VCI addition. Long term corrosion tests in the hot steam generating closed loop system showed a decreased corrosion rate from 8.2-8.9 mpy for the control sample to 0.72-0.74 mpy when washed with 500 ppm VCI solution and subsequently maintained at 100 ppm inhibitor for the test remainder. When inhibitor added at beginning of test resulted in corrosion rate of 1.09-1.24 mpy (with 100 ppm VCI). XPS analysis showed that the amine based inhibitor promoted and stabilized a protective (Fe3O4) magnetite oxide on the pipe internals.

Geothermal brines typically contain dissolved minerals and gases that can cause calcium carbonate silica/silicate and iron sulphide scale deposition in wells and on topside equipment. The presence of scale within a geothermal system can cause various issues that can lead to decreased efficiency of thermal energy production.The high temperatures of geothermal wells can create quite a challenge for scale control in terms of inhibition performance and thermal stability and this limits the chemistry of scale inhibitors that can be applied under these conditions. For calcium carbonate scale control phosphonates often display better inhibition capability than polymers as well as increased brine tolerance.However the thermal stability limits for low molecular weight phosphonates which typically provide good calcium carbonate inhibition are limited to 170°C- 200°C and this temperature can often be too low for geothermal wells. There is therefore a need to develop a novel phosphonate chemistry with a higher temperature stability up to 250°C for geothermal application.The thermal aging data at 250°C for the novel phosphonate chemistry will be presented and furthermore for calcium carbonate details will be provided of scale inhibition performance testing in geothermal brines compared with other traditional phosphonates and polymeric scale inhibitors at 250°C. The calcium carbonate inhibition performance was determined using dynamic scale loop (DSL) tests using a standard industry technique adapted for high temperature geothermal conditions.This study presents details of the development of novel phosphonate scale inhibitor that has been designed to work against calcium carbonate scales at temperatures up to 250°C. The new product is biodegradable calcium tolerant and has the capability to be deployed by continuous injection or in downhole scale squeeze treatments if necessary.

As the oil industry continues to operate in more complex and ultrahigh temperature environments scale control becomes an ever increasing challenge. Scale inhibitors are being pushed to their operational limits and start to lose their efficiency against both calcium carbonate and calcium sulphate scales at >200°C. It is therefore essential to develop the next generation scale inhibitor to work effectively in harsh high temperature environments such as steam floods and geothermal wells.In this study details will be provided of the thermal stability of a novel biodegradable phosphonate scale inhibitor at temperatures up to 250°C. In addition examples of calcium sulphate and calcium carbonate scale control will be provided at 200°C and 250°C respectively where the inhibition performance of the novel phosphonate has provided significant improvements compared to other phosphonates and polymeric scale inhibitors known to be stable at high temperature.The work for calcium sulphate has focussed on steam flood applications where downhole temperatures reach ~200°C and the scale inhibition performance was tested using dynamic scale loop tests based upon a known industry standard procedure. Calcium carbonate inhibition was also tested at 200°C using a similar procedure and in addition with a geothermal brine at 250°C.  The new phosphonate scale inhibitor has also been designed to be biodegradable and can be deployed by both continuous injection and scale squeeze treatment. Careful consideration was also given in the molecular design process for high calcium tolerance and details of brine compatibility at high temperature will be provided.This paper presents details of the development of a biodegradable thermally stable and calcium tolerant phosphonate scale inhibitor for both calcium sulphate and calcium carbonate scale control in ultrahigh temperature environments at ≥200°C. In addition the environmental test data will be discussed along with a field example of deployment of the new phosphonate scale inhibitor for calcium carbonate scale control in a high calcium brine (30000mg/l) in West Africa.

Slurry pipelines are critical systems used in oil sands mining operations to efficiently transport ore from the mine site to centralized extraction facilities. One of the main challenges in designing these systems is the screening and selection of optimal pipeline materials. Slurry pipelines in oil sands mining (hydro-transport and tailing lines) are subjected to aggressive abrasion and erosion-corrosion conditions resulting in relatively rapid material wear rates. For some operations the degradation of these pipelines can result in significant maintenance and replacement costs. To address this issue operators are constantly looking for new material systems which can be used to increase wear resistance and run-life of pipeline systems. Numerous lab-scale test methods exist to assess and rank the ability of materials to resist abrasive conditions but no definitive method is recognized as a standard by industry (other than costly field testing). In the first part of this paper the relative merits of a number of currently available lab-scale testing methods used to characterize material wear are critically assessed. To highlight these merits comparative tests were performed on a variety of materials including a number of polymers and carbon steel. Results show that the ranking of material performance varies with test method used and highlights the importance (and difficultly) in selecting an appropriate test method that represents actual service conditions.In the second part of this paper the development and preliminary assessment of a novel wet wheel abrasion test apparatus is showcased. The intent of this new method is to better simulate the wear mechanisms found in multiphase pipelines with dense-bed slurry flows. Preliminary tests were performed on a number of novel titanium-carbide (Ti-C) reinforced polyurethane materials with two distinct particle size ranges. Performance was evaluated by comparing results to a conventional steel alloy commonly used by the industry and an unreinforced polyurethane system. Wear mechanisms were assessed through microscopy and wear scar profile analysis. A discussion is also provided of the key benefits of this test method (including the potential for assessing the effects of dissolved oxygen and/or fluid chemistry effects) and future work required to validate this novel test system.

This paper will outline the development of a novel Yellow Metal corrosion inhibitor with improved corrosion control capabilities when compared to traditional Azole technology. A four-year R&D effort has led to a new patent pending molecule that develops a more robust film greatly reducing the impact of high levels of halogen on the corrosion of copper and copper alloy heat transfer surfaces. This paper will briefly outline laboratory corrosion testing and film formation and focus on field applications.

Most of the corrosion prediction models used for design of oil and gas lines carrying high pCO2 are valid up to 10-20 bars of pCO2 and are very conservative at higher pCO2 because they do not account for the effect of high pCO2 on the water chemistry and the corrosion mechanism. The present work was focused on developing a predictive tool for near-critical and supercritical CO2 corrosion of mild steel. It incorporates changes in the water chemistry module due to update solubility and dissociation equations changes in the electrochemical module due to the presence of a thick and porous corrosion product layer and consideration of an adsorption mechanism for H2CO3 at the steel surface. The comparison between experimental results and model predictions showed a good agreement under various pressure and temperature ranges.

Third Party Damage (TPD) represents the largest threat to the integrity of onshore oil and gas pipelines. There exist needs for developing reliable models that can quantify the probability of pipeline exposure to TPD threats. Bayesian network(BN) modeling possesses the advantage to quantify the uncertainties and identify where the reduction of these uncertainties has the greatest benefit in terms of the overall failure. This paper reports a modeling approach using Bayesian Network to quantify the Mechanical damage (a major form of TPD) threats to pipeline. Case studies to exam excavation and moving vehicles damages to the pipeline were reported where the conditional probability tables (CPT) of the model were created based on the pipeline operator’s records public data-bases and literatures as well as information obtained from Subject Matter Experts. This model examines TPD failure mechanisms in three parts including Exposure (likelihood of a force or failure mechanism reaching the pipe when no mitigation applied) Mitigation (actions devices conditions etc. that keep the force or failure mechanism off the pipe) and Resistance (the system’s ability to resist a force or failure mechanism applied to the pipe). Using this model pipeline segment with a higher risk to excavation and moving vehicles damages can be identified and suitable mitigation technology can then be implemented to reduce the risk.

Regulatory groups require gas storage facility operators to address the safety and environmental concerns that would be impacted due to a release of the processing fluid. The objective of this paper is to disseminate a process that operators can use to develop an ultrasonic thickness (UT) monitoring program with reliable and reproducible results that meet the fitness-for-service requirements set forth by industry. This paper targets Class 1 Type A components using a Level 1 assessment approach. These components represent the high risk assets subject to design equations that specifically relates to pressure and where supplemental loading does not govern required wall thickness i.e. the required thickness is based on pressure only. A systematic approach to the organization and implementation of the program complete with mathematical equations to evaluate components for fitness-for-service requirements and justification for asset retirement is provided.