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The first presentation will demonstrate how an integrated and systematic approach to predicting scaling potential was used to appropriately monitor and manage scale during unconventional production. The next case study will show how computational fluid dynamics modelling helped on the Nova Field to significantly improve scale inhibitor squeeze placement in an open hole horizontal with large reservoir pressure differences along the well, through the application of non-Newtonian fluids and inflow control devices. Finally, a study involving the comparison of carbonate scaling tendency and scavenging ability of six different H2S scavengers will show that chemistries are available that scavenge efficiently and do not increase carbonate scaling tendency.
World demand for energy is substantial and continues to grow. By 2020, it is expected that the world will need approximately 40% more energy than today, for a total of 300 million barrels of oil-equivalent energy every day. Meeting higher energy demands will require a portfolio of energy-generation options including but not limited to oil, natural gas, coal, nuclear, steam, hydro, biomass, solar and wind.
New horizons are being explored. Wells are drilled in greater water depths. Drilling units are continually upgraded to target deeper hydrocarbon-bearing zones. Wellbore tubular metallurgy is continually upgraded. Drilling, completion and stimulation fluids are being developed for extreme temperature and pressure environments.
As the preferred technology to enhance "oilfield" energy production, well stimulation has and will continue to have an important role in fulfilling the world's future energy needs. Well stimulation generally uses fluids to create or enlarge formation flow channels, thereby overcoming low permeability, as in "tight?? formations, and formation damage, which can occur in any formation type. A common and very successful stimulation option, matrix acidizing, utilizes acids that react to remove mineral phases restricting flow. Depending on the formation and acid type, flow is increased by removing pore-plugging material; or by creating new or enlarged flow paths through the natural pore system of the rock. However, higher-temperature environments present a challenge to matrix acidizing effectiveness. High temperatures can negatively affect stimulation fluid properties and certain acid reactions. Thus, careful fluid choice and treatment designs are critical to successful high-temperature matrix acidizing.
With proper fluid selection, design, and execution, matrix acidizing can be applied successfully to stimulate high-temperature oil & gas wells and geothermal wells. These types of wells have some common features, but they also have significant differences (e.g., completions, mineralogy, formation fluids and formation flow) that influence stimulation designs and fluid choices.
This paper summarizes best practices for designing matrix acidizing treatments and choosing stimulation fluids for high-temperature oil & gas wells and geothermal wells. Included are case histories from Central America. Lessons learned about differences and commonalities between stimulation practices in these well types are also discussed.
Hydrochloric acid (HCl) is the acid of choice for acidizing operations in most carbonate formations and is the base acid commonly paired with others such as hydrofluoric (HF) in most sandstone applications. However, high dissolving power, high corrosion rate, lack of penetration, and sludging tendency coupled with high temperature can make HCl a poor choice. Alternatively, weaker and less corrosive chemicals such as organic acids can be used instead of HCl to avoid these issues. The objective of this paper is to provide an intensive review on recent advancements, technology, and problems associated with organic acids. The paper focuses on formic, acetic, citric, and lactic acids.
This review includes various laboratory evaluation tests and field cases which outline the usage of organic acids for formation damage removal and dissolution. Rotating disk apparatus results were reviewed to determine the kinetics for acid dissolution of different minerals. Additional results were collected from solubility, corrosion, core-flooding, Inductively Coupled Plasma (ICP), X-Ray Diffraction (XRD), and Scanning Electron Microscope Diffraction (SEM) tests.
Due to their retardation performance, organic acids have been used along with mineral acids or as a stand-alone solution for high-temperature applications. However, the main drawback of these acids is the solubility of reaction product salts. In terms of conducting dominant wormhole tests and low corrosion rating, organic acids with low concentrations show good results. Organic acids have also been utilized in other applications. For instance, formic acid is used as an intensifier to reduce the corrosion rate due to HCl in high-temperature operations. Acetic and lactic acids can be used to dissolve drilling mud filter cakes. Citric acid is commonly used as an iron sequestering agent.
This paper shows organic acid advances, limitations, and applications in oil and gas operations, specifically, in acidizing jobs. The paper differentiates and closes the gap between various organic acid applications along with providing researchers an intensive guide for present and future research.
As the world's population grows, its thirst for water continues to increase. Yet, the total amount of freshwater that is available naturally does not replenish quickly enough to match this growth. Consequently, increase in water consumption and continuous drainage has resulted in a growing shortage for industrial use.
In the oil and gas industry, significant volumes of water are used to carry out various treatments such as water injection, matrix acidizing, and multistage hydraulic fracturing. Fresh water is clean and contains low salt content, making it the ideal water source to mix these treatments with ease. However, as unconventional and tighter formations are developed, the use of water in such treatments exponentially increases. Trucking, piping and shipping freshwater for oil and gas purposes becomes both uneconomical and unethical, especially for offshore operations.
Seawater has been gaining attention as a viable alternative to freshwater in the oil and gas industry. Ideally, the most cost-effective way is to use raw seawater. However, raw seawater contains ions and microorganisms that can introduce or exacerbate scaling, corrosion, bacterial problems, and most importantly hinder desired fluid performance. Therefore, seawater is typically treated to remove adequate quantities of these components. Since treatment of seawater is increasing in popularity, it is important to realize which components are necessary to remove, to achieve a balance between treatment cost and treatment benefit.
In this review, a complete picture of seawater as an alternative to fresh water will be presented. This includes examining the reason for using seawater, the challenges faced, the technologies developed, and many applications of seawater based treatment fluids. Through this, readers should be able to gain a complete picture of the problem at hand and the solutions available to tackle it.
Water plays an extremely important role in many industries ranging from textiles to the oil and gas operations. Particularly in the oil and gas industry, fresh water is ideal to synthesize treatment fluids and is frequently used. However, to meet the needs of a growing population and to compensate for the declining reserves of fresh water, the cost of using fresh water has increased significantly. Furthermore, in areas without readily available sources of freshwater, the cost incurred transporting fresh water to the field can be significant. Therefore, the industry is increasingly turning to alternative sources of water to meet their requirements. One such alternative is seawater, which is a popular choice due to its natural abundance and low transportation cost, especially in coastal areas.
Zhao, Xiaodong (School of Electromechanical Engineering, Zhejiang Ocean University Zhoushan, Zhejiang, China) | Yang, Jie (School of Electromechanical Engineering, Zhejiang Ocean University Zhoushan, Zhejiang, China) | Fan, Xiqiu (School of Electromechanical Engineering, Zhejiang Ocean University Zhoushan, Zhejiang, China) | Duan, Jizhou (Institute of Oceanology, Chinese Academy of Sciences Qingdao, Shandong, China)
In the presence of sulfate-reducing bacteria(SRB), hematite(α-Fe2O3) dissolution is affected potentially by a combination of enzymatic (hydrogenase) reduction with hydrogen sulfide oxidation. As a consequence, ferrous ions are free to react with excess H2S to form insoluble iron sulfides. Morphology of single crystalline hematite cubes, prepared by a hydrothermal synthesis at 130°C from a solution of urotropine ((CH2)N4) and ferric chloride, and its metamorphosis to iron sulfides in SRB-containing medium are observed by transmission electron microscopy in the present study. Iron oxide hydrate (Fe2O3·H2O) and the γ-FeOOH form of hydrated ferric oxide are the primary forms of corrosion product. Two typical morphologies of iron sulfides, globule and plate, are observed after immersion of about a month. The morphological changes of the corrosion product are interpreted from analyses made using energy dispersive spectroscopy (EDS) and the spectra confirm that the plates and the globules are different morphologies of the same chemical species, iron sulphide product. Electron diffraction identifies the presence of a hexagonal structure associated with observed crystallites, indicating the identification of the iron sulfide phase as pyrrhotite.
Sulfate-reducing bacteria, belonging to anaerobe, exist widely in the polluted seawater and sea mud. SO42- can be reduced to S2- by their metabolic activities, and H2S formed in aqueous solution results in the corrosion damage of metal pipelines and constructions, as well as pollution of environment. Comprehensive research has been carried out in terms of microbiologically influenced corrosion (MIC) of carbon steel and low alloy steel in environment containing SRB(Tiller,1983). Iron oxide occurs with the formation of ferrous sulfide or before it in the primary stage of the corrosion process. Iron oxide should be responsible for the emergence and development of MIC, which haven’t been well investigated yet. In the environment abundant in sulfide, metal oxide may react with sulfide as the resource of metal ions.