Amid concerns over negative the environmental impacts of offshore chemicals, Baker Hughes explored new chemistries to develop environmentally friendly kinetic hydrate inhibitors (KHI). Our efforts were focused on improving biodegradability and toxicity of KHIs to meet environmental protection requirements, as well as mitigating challenges in field applications. A novel KHI design with branched polymers containing sugar alcohol ester groups as linkages, was proposed and synthesized. The new KHI polymer demonstrated > 20% biodegradability and >100 mg/L toxicity to seawater algae, and it also exhibited competitive or even better KHI performance to traditional non-biodegradable KHI products. Additionally, new KHI showed improved stability in water/brine at elevated temperatures as compared to traditional KHI products, which might mitigate concerns on polymer deposition at high temperatures.
The presence of hydrogen sulfide in high pressure gas systems causes several complications. Sour gas corrosion is a major concern in the oil and gas industry due to the presence of localized corrosion. At high pressures and low temperatures hydrates can occur. Sour gas decreases the pressure and increases the temperature at which hydrate formation occurs. Operators have used both corrosion inhibitors and kinetic hydrate inhibitors to decrease the capital requirements of developing sour high pressure gas systems. The development of sour gas corrosion inhibitors that are compatible with kinetic hydrate inhibitors is a major requirement for qualifying corrosion inhibitors for these applications. This paper describes laboratory work on the development of a new corrosion inhibitor by performing various performance and compatibility tests with kinetic hydrate inhibitor. The new corrosion inhibitor needed to meet various additional requirements which made the development process even more complex. The partitioning of a corrosion inhibitor between the oil and water phases has a significant impact on inhibitor selection and treatment strategy. General corrosion performance was addressed using mass loss and electrochemical data. Evaluation of localized attack was performed using vertical scanning interferometry (VSI). The main advantage of this approach is in providing quantitative data for product performance differentiation in the presence of localized corrosion. Introduction The production and transportation of oil and gas fluids in remote locations as well as under sever climate conditions can present major technical challenges to operators1. This is because of the inherent characteristics of produced fluids, which can lead to operational issues such as corrosion, hydrate occurrence, scaling, wax and/or paraffin deposition2–5. Changes to the properties of produced fluids over the life cycle of an asset can also introduce operational complications. Consequently, a thorough consideration of these various issues is necessary in order to maintain flow assurance and assets integrity during the lifetime of a producing field. The transportation of unprocessed fluids from offshore to onshore processing facilities is an attractive economic incentive since significant capital savings can be achieved. This kind of operational practice can bring along the potential risks of corrosion and hydrate formation in wet gas transportation systems6. The main cause of these problems is the presence of water, and dissolved in it acid gases like carbon dioxide (CO2) and/or hydrogen sulfide (H2S) which generates a highly corrosive environment. The presence of organic acids and other dissolved species can greatly enhance the corrosively of produced fluids as well. A significant amount of H2S can be present in sour systems; however, the general corrosion rate of carbon steel is generally low due to the presence of a semi-protective iron sulfide film on the surface. The main mode of corrosion in this case is localized attack or pitting. A viable solution to control this type of corrosion attack is the application of corrosion inhibitors to provide protection of carbon steels.
Gas hydrate formation and control is a critical flow challenge that many offshore oil and gas production operations encounter. Formation of hydrates can cause blockage of production flowlines, chokes and valves, which can result in catastrophic failures. Compared to other production problems, hydrate formation is a relatively new phenomenon that is becoming more and more significant with increasing subsea and deepwater developments as well as huge gas projects in the Middle East. The use of low dosage hydrate inhibitors (LDHIs), such as kinetic hydrate inhibitors (KHIs), offer an alternate technical solution to thermodynamic hydrate inhibitors by offering better economics, improved Health, Safety and Environmental (HS&E) performance and less demand on product transportation and storage. This paper summarizes the history, evolution and current state of KHI laboratory testing requirements. Improvements in laboratory techniques to evaluate the performance of KHI in sweet and sour environments will be discussed. The results of the evaluation are based on laboratory conditions and the ability of a KHI to successfully inhibit hydrate formation in sweet and sour rocking cells. Recent testing has shown significant differences between sweet and sour environments and the ability of the KHI to successfully inhibit hydrate formation under laboratory conditions. The secondary properties of a selected KHI are becoming more important so are advances in evaluating these properties, in particular the stability and applicability of a KHI under proposed system conditions. Hydrates may form different structures depending on the gas composition of the produced fluids. The nature of the KHI used needs to take into consideration. Recent product developments in this area show that these challenges can be met with appropriate lab testing. INTRODUCTION Flow assurance is critical during the efficient production of hydrocarbons from offshore and subsea assets. Gas hydrate formation and control is a critical flow assurance challenge that many offshore oil and gas production operations encounter. The interaction of low-molecular weight gases such as small chain hydrocarbon, and acidic gases like carbon dioxide and hydrogen sulfide, with water under "high" pressure and "low" temperature within a pipeline can form gas hydrates. Gas hydrates are essentially a gas molecule encapsulated by water molecules which have an ice like appearance. Two types of hydrate structure form in gas pipelines, type II being the most common and associated with larger gas molecules such as ethane and propane and type I mainly associated with lean gas and/or carbon dioxide or hydrogen sulfide production. Gas hydrate crystals may agglomerate and/or anneal to form plugs that results in lost production and may incrase (HS&E) risks. Formation of hydrates can cause blockage of production flowlines, chokes and valves, which can result in potentially catastrophic failures.
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