Mercury Contamination of Process and Pipeline Infrastructure - A Novel, All- Encompassing Solution for the Evaluation and Decontamination of Mercury from Pipelines and Topside Process Equipment to allow Safe Disposal

2021 ◽  
Author(s):  
Stuart Baker ◽  
Mark Andrew ◽  
Matthew Kirby ◽  
Matthew Bower ◽  
David Walls ◽  
...  
Keyword(s):  
Chemical Treatment ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Mercury Contamination ◽  
Process Equipment ◽  
Worker Exposure ◽  
Internal Surfaces ◽  
Operational Life ◽  
Decontamination Solution

Abstract Mercury present in produced oil and gas will deposit onto the internal process infrastructure via a number of mechanisms including chemisorption and adsorption with the primary mechanism being through reaction with iron sulphide to form mercury sulphide. Due to the volumes of fluids produced and the length of time facilities are in production, even where the produced fluids have historically contained relatively low concentrations of mercury, pipeline scales containing percentage levels of mercury may be present. Thus, aged facilities and infrastructure that have reached the end of their operational life and are selected for either recycling or abandonment, may pose a serious risk to health and the environment if the decommissioning process is not managed correctly. Smelting, hot cutting or other thermal/abrasive surface preparations for example, can lead to significant release of elemental mercury, a worker exposure hazard. Alternatively, if sub-sea pipelines are abandoned in-situ, all mercury present will ultimately be transferred to the local ecosystems. Consequently, the oil and gas industry have the requirement for a complete mercury decontamination solution from initial evaluation, demonstrable cleaning efficacy through to a guarantee for the treatment and disposal of the mercury waste generated in an environmentally-friendly manner. In order to decide upon the most appropriate decontamination solution, an evaluation of the extent of mercury contamination should be undertaken. A novel approach that has recently been successfully implemented involved analysis of pipe sections by multiple analytical techniques, providing the mercury concentration in the scale/steel. From this, the total mass of mercury across the process or pipeline was approximated. Subsequently, the efficacy of the preferred chemical to remove mercury from the internal surfaces of pipework was evaluated by chemical treatment of the pipe sections under laboratory conditions. In-situ decontamination can be performed by a number of applications, including (i) the use of chemical pig trains in pipelines, (ii) closed loop circulation of chemical around topside process equipment and (iii) high pressure spraying of large surface areas such as storage tanks, FSO / FPSO vessels. The mercury waste generated is treated, on site or off site, to minimise the volume and disposed of in accordance with international regulations. An all-encompassing mercury decontamination solution is described. Trials involving the chemical treatment of steel sections have demonstrated that more than 97% of the mercury deposited can be removed from the internal surfaces of pipelines and safely disposed of, significantly reducing the risk of (i) mercury release to the environment and (ii) worker exposure to mercury during smelting activities.

LEGAL FRAMEWORK AND LIABILITY OF LEAVING OIL AND GAS FACILITIES IN-SITU OR DEEP SEA DISPOSAL ON AUSTRALIA’S CONTINENTAL SHELF

2004 ◽  
Vol 44 (1) ◽  
pp. 809
Author(s):  
I.V. Stejskal
Keyword(s):  
Continental Shelf ◽  
Oil And Gas ◽  
Petroleum Industry ◽  
Legal Framework ◽  
Gas Production ◽  
Economic Life ◽  
Oil And Gas Production ◽  
Operational Life ◽  
Accepted Practice

Australia’s offshore petroleum industry is beginning to mature and many of its offshore oil and gas production facilities are reaching the end of their operational life. These facilities consist of an array of infrastructure including wells, wellheads, platforms and monopods of various construction, pipeline and flowlines, and anchors and risers. Many of these facilities will need to be decommissioned at the end of their operational and economic life in a safe and environmentally responsible manner.The Australian government has the jurisdiction to direct a company to remove all facilities associated with offshore production projects located on Australia’s continental shelf, but there is room for discretion for other decommissioning options. The manner in which facilities are decommissioned must be assessed on a case-by-case basis, taking into account factors such as technical feasibility, commercial risk, safety and social impacts, costs and environmental effects.Two decommissioning options appropriate in some instances are to leave selected facilities in-situ or dispose of a facility to some other location on the continental shelf, preferably in deep water. Residual liability refers to the responsibility and liability associated with leaving facilities on the seabed. If a facility is allowed to remain on the seabed, questions related to residual liability arise:who is responsible for any facility left on the seabed; andwho is liable to pay for compensation in the event that this facility is allowed to remain in place on the seabed and injury or damage is caused to a third person or property?There is no universally accepted practice in relation to residual liability in relation to decommissioning. In some countries, the State assumes responsibility; in other countries the company remains responsible in perpetuity. This issue still needs to be clarified in Australia.

scholarly journals LEXICAL-SEMANTIC FEATURES OF THE ENGLISH TERMINOLOGY OF OIL AND GAS SPHERE

2020 ◽  
Vol 1 (9(77)) ◽  
pp. 164-168
Author(s):  
Mariana Shtohryn ◽  
Myroslava Muchka
Keyword(s):  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Gas Production ◽  
Process Equipment ◽  
Semantic Features ◽  
Gas Industry ◽  
Oil And Gas Production ◽  
Heterogeneous Model ◽  
Lexical Semantic ◽  
Semantic Categories

The lexical-semantic features of the English terms of oil and gas sphere are considered. Attention is drawn to the phraseological and metaphorical features that are characteristic of the terms of the oil and gas industry. It has been revealed that English oil and gas terminology is built on a heterogeneous model, that is, the result of the interaction of several areas of human knowledge. It includes geological, geophysical, geochemical terms, as well as terms related to drilling, washing, fastening and cementing of oil and gas wells, development of oil and gas fields, underground hydraulics, oil and gas production, processing methods, pipeline terminology, offshore drilling terminology, economic terminology. It is has been found out that the semantic categories of English oil and gas terminology are evidence that the terminology under study reflects a particular sphere of human activity that can be structured in some way by the means of language. In this process, the human factor is important. On the one hand, it is inherent in each of the categories, and serves as a basis for subjectivity in identifying the peculiarities of the content.The semantic categories of English oil and gas terminology are analyzed. These include: Human, Process, Equipment, Substance, Method, and Characteristics. The study showed that among the English oil and gas terms formed by metaphorization, we can distinguish terms conventionally grouped under the following lexical-semantic groups: “Parts of the human body”, “World of animals and birds”, “Clothes”, “Society”, “Cooking”, “Construction”, “Nature”, “Traveling”, “Weapon”, “Tool”, “Geometric figure”, “Hunting”, “Fishing”, “Medicine”, “Furniture” та “Quality”.

Best Practices for the Design and Installation of Bolted Joints

2004 ◽  
Author(s):  
Debra Tetteh-Wayoe
Keyword(s):  
Best Practices ◽  
Oil And Gas ◽  
Cost Effective ◽  
Field Testing ◽  
Oil And Gas Industry ◽  
Bolted Joints ◽  
Pipeline System ◽  
Technical Literature ◽  
Operational Life ◽  
Welded Pipe

The cost effective design and construction of liquid pipeline facilities traditionally necessitates the use of bolted joints as opposed to welds. Some of these bolted joints are frequently disassembled and reassembled as part of regular maintenance, while others are assembled at the time of construction and expected to retain a seal for the lifetime of the pipeline. Consequently, the design and installation practices employed for bolted connections are relied upon to produce the same operational life and integrity as welded pipe. In an effort to ensure that the bolted joints used on our pipeline system are as reliable as our welded joints, we investigated industry best practices for flange assembly and the root causes of joint failure. We have completed extensive research of technical literature, including the torquing procedures used in various industries, and performed field-testing on our own system. Generally we have found that: • Flange assembly failures and concerns about this issue are common in the oil and gas industry; • Practices for tightening flanges are inconsistent; and • To accomplish and retain an effective gasket seal, and thus minimize life cycle leaks, one has to consider many factors, including the amount of torque applied to nuts, the stud and nut friction, the type of gasket used, the size of the studs/nuts/flanges, the type of equipment used for tightening, the calibration of the torquing equipment, flange face alignment, and torquing sequence. Using the results of our investigation, we implemented several measures to enhance both the quality and the long-term integrity of our bolted flange connections. This paper describes the results of our investigations, as well as the practices implemented for flange assemblies required for maintenance and new construction activities.

The CSIRO In-Situ Laboratory in South Western Australia: a field laboratory for de-risking carbon storage

2020 ◽  
Vol 60 (2) ◽  
pp. 732
Author(s):  
Karsten Michael ◽  
Ludovic Ricard ◽  
Linda Stalker ◽  
Allison Hortle ◽  
Arsham Avijegon
Keyword(s):  
Carbon Storage ◽  
Western Australia ◽  
Oil And Gas ◽  
Technology Development ◽  
Ground Surface ◽  
Oil And Gas Industry ◽  
Research Field ◽  
Field Site ◽  
Monitoring Technologies

The oil and gas industry in Western Australia will need to address their carbon emissions in response to the state government’s aspiration of net zero greenhouse gas emissions by 2050. The geological storage of carbon dioxide is a proven technology and an option for reducing emissions. Storage operations would need to provide adequate monitoring systems in compliance with yet to be defined regulations and to assure the public that potential leakage could be confidently detected, managed and remediated. The In-Situ Laboratory in the south-west of Western Australia was established as a research field site to support low emissions technology development and provides a unique field site for controlled CO2 release experiments in a fault zone and testing of monitoring technologies between 400 m depth and the ground surface. A first test injection of 38 tonnes of food-grade gaseous CO2 in 2019 demonstrated the ability to detect less than 10 tonnes of CO2 with fibre optic sensing and borehole seismic testing. Results from the previous test and future experiments will help to improve the sensitivity of monitoring technologies and could contribute to defining adequate monitoring requirements for carbon storage regulations.

Managing climate change adaptation in oil and gas production

2015 ◽  
Vol 55 (2) ◽  
pp. 456
Author(s):  
Paul van der Beeke
Keyword(s):  
Climate Change ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Business Case ◽  
Climatic Conditions ◽  
Gas Production ◽  
Extreme Weather Events ◽  
Oil And Gas Production ◽  
Climate Change Effects ◽  
Operational Life

Oil and gas production operations occur in widely diverse onshore and offshore contexts. The global industry has a long history of coping with climate variability, extreme climatic conditions and extreme weather events. Climate change, however, is projected to take the new climate beyond the range of historical variability in many places where oil and gas production facilities are located. Oil and gas infrastructure often has an expected operational life of 50 years or more, which would take new operations to 2064 and beyond. This is well inside the timeframe predicted for substantial climate change with consequent risks to longer term operational continuity and supply chain security. In recent years, the realities of climate change beyond pre-industrial age historical variability, and the associated business risks, have become accepted by the major global oil and gas industry players. Other stakeholders, including corporate, institutional and private investors and corporate regulators, are also becoming more assertive in their demands for corporate disclosure of climate change risks, adaptation management plans and evidence of effective implementation of adaptive measures. Industry decision-makers need scientifically sound and robust data applied to their specific operations and business conditions to support business case-based investment decisions for new project feasibility, capital and operational expenditure, and the management of long-term strategic liabilities. This extended abstract provides an overview of the complex and interconnected web of climate change effects that should be considered. It also outlines approaches that could be employed to manage the risks and meet stakeholder expectations.

Canadian Operator Works To Transform an Oil Field Into a Hydrogen Factory

2021 ◽  
Vol 73 (03) ◽  
pp. 38-40
Author(s):  
Trent Jacobs
Keyword(s):  
Hydrogen Production ◽  
Heavy Oil ◽  
Oil And Gas ◽  
Hydrogen Generation ◽  
Combustion Process ◽  
Oil And Gas Industry ◽  
Oil Field ◽  
In Situ Combustion ◽  
Associated Gas

As the oil and gas industry scans the known universe for ways to diversify its portfolio with alternative forms of energy, it might want to look under its own feet, too. For inside every oil reservoir, there may be a hydrogen reservoir just waiting to get out. The concept comes courtesy of Calgary-based Proton Technologies. Founded in 2015, the young firm is the operator of an aging heavy oil field in Saskatchewan. There, on a small patch of flat farm-land, Proton has been producing oil to pay the bills. At the same time, it has been experimenting with injecting oxygen into its reservoir in a bid to produce exclusively hydrogen. Proton says its process is built on a technical foundation that includes years of research and works at the demonstration scale. Soon, the firm hopes to prove it is also profitable. While it produces its own hydrogen, Proton is licensing out the technology to others. In January, fellow Canadian operator Whitecap Resources secured a hydrogen production license of up to 500 metric tons/day from Proton. Whitecap produces about 48,000 B/D, and thanks to carbon sequestration, the operator has claimed a net negative emissions status since 2018. Proton says it has struck similar licensing deals with other Canadian operators but that these companies have not yet made public announcements. Where these projects go from here may end up representing the ultimate test for Proton’s innovative twist on the in-situ combustion process known so well to the heavy-oil sector. “In-situ combustion has been used in more than 500 projects worldwide over the last century. And, they have all produced hydrogen,” said Grant Strem, a cofounder and the CEO of Proton. Strem is a petroleum geologist by back-ground who spent the majority of his career working on heavy-oil projects for Canadian producers and research analysis with the banks that fund the upstream sector. While his new venture remains registered as an oil company, the self-described explorationist has come to look at oil fields very differently than he used to. “In an oil field, you have oil—hydrocarbons, which are made of hydrogen and carbon. The other fluid down there is H2O. So, an oil field is really a giant hydrogen-rich, energy-dense system that’s all conveniently accessible by wells,” Strem explained. But, in those past examples, the hundreds of other in-situ combustion projects, hydrogen production was merely a byproduct, an associated gas of sorts. It was the result of several reactions generated by air injections that producers use an oxidizer to heat up the heavy oil and get it flowing. What Proton wants to do is to super-charge the hydrogen-generating reactions by using the oil as fuel while leaving the carbon where it is. That ambition includes doing so at a price point that is roughly five times below that of Canadian natural gas prices and an even smaller fraction of what other hydrogen-generation methods cost.

Seismic field data displaying azimuthal anisotropy, 1986–2020

2020 ◽  
Vol 8 (4) ◽  
pp. SP135-SP156
Author(s):  
Heloise Lynn
Keyword(s):  
Field Data ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
In Situ Stress ◽  
Azimuthal Anisotropy ◽  
Amplitude Variation ◽  
Gas Industry ◽  
The Past ◽  
Vertically Aligned

The azimuthal (az’l) processing of 3D full-azimuth full-offset P-P reflection seismic data can enable better imaging, thus yielding improved estimates of structure, lithology, porosity, pore fluids, in situ stress, and aligned porosity that flows fluids (macrofracture porosity). In the past 34 years, the oil and gas industry has significantly advanced in the use of seismic azimuthal anisotropy, in particular, to gain information concerning unequal horizontal stresses and/or vertically aligned fractures, and possibly more importantly, to improve the prestack imaging especially in complex structure. The important development stages during the past 40 years were enabled by industry advancements in acquisition, processing, theory, and interpretation. The typical important techniques became evident in PP amplitude variation with angle and azimuth (AVAaz) and orthorhombic imaging. These techniques addressed the complications due to wave propagation in birefringent media. PP AVAaz, now industry standard for vertically aligned fracture characterization, is accompanied by a near-angle azimuthal amplitude variation when aligned connected porosity that flows fluids is present. Birefringence is present with unequal horizontal stresses and/or vertically aligned fractures that flow fluids. I have focused on the field-data documentation of the relationships among azimuthal P-P reflection data, S-wave birefringence, and hydrocarbon production. With increases and improvements in acquisition and processing, plus today’s powerful versatile interpretation platforms, continual advances beyond orthorhombic (ORT) into monoclinic and triclinic symmetries are to be expected. The use of 3D azimuthal seismic for time-lapse changes of the in situ stress field, fracture populations, and pore fluids, as rocks undergo production processes (oil and gas reservoir production processes, wastewater disposal, etc.) and at plate boundaries where stresses change, offers great potential to benefit not just the oil and gas industry but all of humanity.

scholarly journals Tube Expansion Under Various Down-Hole End Conditions

2013 ◽  
Vol 10 (1) ◽  
pp. 25 ◽  
Author(s):  
FJ Sanchez ◽  
OS Al-Abri
Keyword(s):  
Global Economy ◽  
Structural Integrity ◽  
Oil And Gas ◽  
Petroleum Industry ◽  
Behavioral Changes ◽  
Theoretical Formulation ◽  
Operational Life ◽  
Tube Expansion ◽  
Oil Gas

Fossil hydrocarbons are indispensables commodities that motorize the global economy, and oil and gas are two of those conventional fuels that have been extracted and processed for over a century. During last decade, operators face challenges discovering and developing reservoirs commonly found up to several kilometers underground, for which advanced technologies are developed through different research programs. In order to optimize the current processes to drill and construct oil/gas wells, a large number of mechanical technologies discovered centuries ago by diverse sectors are implemented by well engineers. In petroleum industry, the ancient tube forming manufacturing process founds an application once well engineers intend to produce from reservoirs that cannot be reached unless previous and shallower troublesome formations are isolated. Solid expandable tubular is, for instance, one of those technologies developed to mitigate drilling problems and optimize the well delivery process. It consists of in-situ expansion of a steel-based tube that is attained by pushing/pulling a solid mandrel, which permanently enlarge its diameters. This non-linear expansion process is strongly affected by the material properties of the tubular, its geometry, and the pipe/mandrel contact surface. The anticipated force required to deform long sections of the pipe in an uncontrollable expansion environment, might jeopardize mechanical properties of the pipe and the well structural integrity. Scientific-based solutions, that depend on sound theoretical formulation and are validated through experiments, will help to understand possible tubular failure mechanisms during its operational life. This work is aimed to study the effect of different loading/boundary conditions on mechanical/physical properties of the pipe after expansion. First, full-scale experiments were conducted to evaluate the geometrical and behavioral changes. Second, simulation of deformation process was done using finite element method and validated against experimental results to assess the effects on the post-expansion tubular properties. Finally, the authors bring a comparison study where in a semi-analytical model is used to predict the force required for expansion. 

scholarly journals Technological Capabilities of Well Cementing

2021 ◽  
Vol 4 (1) ◽  
pp. 465-478
Author(s):  
Tatiana N. Ivanova ◽  
Michał Zasadzień
Keyword(s):  
Laboratory Tests ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Drilling Mud ◽  
Gas Industry ◽  
Cement Ratio ◽  
Use Of Technology ◽  
Water To Cement Ratio ◽  
Operational Life ◽  
Concrete Mixer

Abstract Cementing of casing string is a final operation before the next stage of well construction; it provides maximum operational life of the well. Cementing of casing string is carried out with the use of technology, based on squeezing of the whole volume of drilling mud by special grouting composition. The main purposes of cementing include isolation of water-bearing horizon, strengthening of borehole walls in unconsolidated and unstable rocks. Well cementing process is divided into five subsequent operations. Firstly, grouting mixture is prepared in concrete mixers (cementing units) with necessary water-to-cement ratio and additives. Secondly, prepared grouting solution is injected in a well. Thirdly, the solution is squeezed into the space between the casing pipes and wellbore walls. Then it is necessary to wait until the cement sheath is hardened. And at last, quality control is carried out. For convenient transportation, the equipment for well cementing is installed on the truck chassis (KAMAZ, URAL and etc.). All components are poured in concrete mixer, then the water is added and everything is being mixed until formation of uniform mass, which is later pumped in a well. Oil and Gas Industry Safety Regulations say that «calculated endurance of casing string cementing should not exceed 75% of time of cement thickening, established by laboratory tests». Therefore, it is necessary to carry out all operations of injection of fluids into the well as soon as possible without any incompliances of the cementing technology. With cementing material used and its water-to-cement ratio of 0.5, the average time of cement thickening is 120 minutes, according to laboratory tests. Therefore, a set of operations of injection of fluids should not exceed 90 minutes.

A High Corrosion and Wear Resistant Interior Surface Coating for Use in Oilfield Applications

2009 ◽  
Vol 83-86 ◽  
pp. 592-600 ◽  
Author(s):  
D. Lusk ◽  
M. Gore ◽  
B. Boardman ◽  
D. Upadhyaya ◽  
T. Casserly ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Chemical Vapour ◽  
Oil And Gas Industry ◽  
Corrosion And Wear ◽  
Wear Testing ◽  
Directional Drilling ◽  
Wear Resistant ◽  
Wear Rates ◽  
Internal Surfaces ◽  
Before And After

A novel technique for depositing thick DLC based films on the inside of cylindrical substrates, like pipes, tubes and valves, has been developed. A plasma enhanced chemical vapour deposition (PECVD) technique has been used to engineer and optimize the above mentioned films for maximum coating performance. Of particular importance is the corrosion and wear resistant qualities of these films. Changes in film chemistry, structure and thickness are attributed to the improved corrosion and wear resistance. Details will be given of the corrosion testing which has taken place, such as exposure to HCL (hot and ambient temperature), NaCl and H2S environments. One such test is a very aggressive sour autoclave test where the film is exposed to an aqueous, organic and gas phase over a 30 day period and no damage to the film was found. In depth details of this sour autoclave test will be shown including photographs of the film before and after testing. Wear testing has also been carried out in dry and wet sand slurry environments where very low coefficient of friction (COF) and wear rates were found. It is believed that this thick DLC based film can increase the component life in applications where internal surfaces are exposed to highly corrosive and abrasive media, in particular the oil and gas industry. Examples of such applications are mud pump sleeves, deep well components, directional drilling, abrasive flow spools, pump barrels and in sour fields (H2S).

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