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scavenger
Anyone who works in the oil and gas industry is aware of hydrogen sulfide (H2S) gas. This is a highly toxic gas that gives rise to "sour" production. H2S is highly corrosive to many common materials used by the industry (e.g., mild steels), and there often are strict fiscal and technical limits placed on upstream oil and gas producers by the midstream and downstream operators. The origin of H2S can be authigenic (i.e., occurs in-situ and naturally in the reservoir, related to the biological origin of the organic matter that produces the crude oil and gas), or it can be caused by biological processes and the action of sulfate-reducing bacteria (e.g., during seawater flooding and contamination of the reservoir). The concentration range of H2S that occurs can vary from a few parts per million (ppm) to many tens of percent of the raw gas production.
Eni began producing oil reserves from the Aquila reservoir in the Adriatic Sea soon after its discovery in the early 1980s. As primary production decreased, a decision was made to begin enhanced recovery with artificial gas lift. With the play in deep water (815 m) and 46 km off the southern coast of Italy, a floating production, storage, and offloading (FPSO) vessel was needed. After a 5-year run, the Firenze halted operations in 2018 because of low oil production. The complete paper examines the decision to use hydrogen-sulfide- (H2S) removal technology, the cost of operation, and the unit's availability over its lifetime.
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Floating production systems (1.00)
Oil production in the Eagle Ford play is now more than 600,000 BOPD. Advances in horizontal drilling have made exploration of unconventional hydrocarbon resources commercially viable, and production in Eagle Ford will only continue to increase for years to come. The positive effects of this include potentially decreasing foreign imports of oil, and thousands of new jobs in the area. However, the challenges for operators in exploiting this unconventional resource have been enormous, ranging from finding adequate human resources, transportation, infrastructure, formation evaluation, and water management. With so many challenges front and center, chemical management can be relegated to the end of the priority list.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Management > Energy Economics > Unconventional resource economics (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract Hydrogen sulphide (H2S) is naturally occurring in many oil and gas production streams. H2S scavengers are used as additives to reduce the concentration of H2S gas in order to meet export gas/crude specification or for mechanical integrity requirement. Most Total installations today use conventional chemicals such as monomethyl amine (MMA) and monoethanolamine (MEA) triazines for H2S removal. According to Total affiliates, deposit formations have been observed when triazine based scavengers are used. In this paper alternative chemistries for H2S scavenging are assessed. Six H2S scavengers have been evaluated, these are: Methylene bis-Oxazolidine (MBO), Ehylenedioxy Dimethanol (EDDM), 2-Ethyl Zinc Salt, Glyoxal, Hemiacetal and MEA Triazine. For the evaluation of H2S scavenger's efficiency, an experimental method has been developed. For the selection of H2S scavengers, the following tests have been carried out: (i) evaluation of H2S scavenger efficiency in the oil and gas phase and (ii) production chemical compatibility test. The three-best performing H2S scavengers have been analysed for (i) the impact of H2S scavenger on foaming; (ii) impact of H2S scavenger on emulsion; (iii) compatibility between H2S scavenger and production water; (iv) effect of H2S on the scale inhibitor efficiency; (v) effect of H2S on the corrosion inhibitor efficiency. Laboratory tests have shown that the three best H2S scavengers, based on the performance test, are Zinc 2-ethylhexanoate, Methylene bis-Oxazolidine (MBO) and Triazine. Methylene bis-Ozaxolidine tested on North Sea site in the multiphase and gas phase has shown preliminary good results. No impact on emulsion, foaming and corrosion were observed from the three-best H2S scavengers selected. Test performed on site with zinc-based product showed very good performance on H2S removal but impacted produced water quality. The zinc-based product formed deposits when mixed with production water therefore this H2S scavenger should not be used for scavenging H2S in the water phase. Though Triazine and MBO based scavengers increase water pH, potential scaling issues can be mitigated by scale inhibitor, however dithiazine deposits formed with the use of triazine based scavengers limits its use for H2S scavenging in oil gas installations. An experimental method has been developed for the evaluation of H2S scavengers. Alternative scavenger chemistries have been identified. These chemistries reduce the risk of deposit formation in the H2S removal process during oil and gas production.
- Europe > United Kingdom > North Sea (0.27)
- Europe > Norway > North Sea (0.27)
- Europe > North Sea (0.27)
- (2 more...)
Evaluation of Hydrogen Sulfide Scavengers for Use with Static Mixers
Lehmann, Marc (INPEX Australia Pty Ltd) | Pojtanabuntoeng, Thunyaluk (Curtin Corrosion Centre Western Australia School of Mines: Minerals, Energy and Chemical Engineering, Curtin University) | Long, Yu (Curtin Corrosion Centre Western Australia School of Mines: Minerals, Energy and Chemical Engineering, Curtin University) | Yookhong, Marisa (Curtin Corrosion Centre Western Australia School of Mines: Minerals, Energy and Chemical Engineering, Curtin University) | Iannuzzi, Mariano (Curtin Corrosion Centre Western Australia School of Mines: Minerals, Energy and Chemical Engineering, Curtin University)
Abstract The efficiency of hydrogen sulfide scavengers directly injected into gas streams is often compromised by short contact times due to space limitations on offshore assets. The use of static mixers is often employed to increase the efficiency of gas-liquid mixing. The performance of two commercially available hydrogen scavenger products were assessed in the laboratory utilising a specially fabricated test chamber designed to mimic a static mixer. A continuous feed of both gas and a liquid scavenger solution were mixed through a glass bead static mixer. The liquid scavenger was atomized into the gas prior to traveling through the bed. The impact of dose rate, water content, carbon dioxide and contact time were assessed on the scavenging efficiency and kinetics of two triazine chemicals used to sequester H2S from a gas stream containing 180 ppmv H2S in nitrogen, to achieve a target H2S concentrations of <10 ppmv. Efficiencies derived from the test apparatus revealed that the formulation based on the ethanolamine triazine chemistry performed significantly better than the methylamine triazine product at the two contact times of 3 and 25 seconds. The equilibration time required to reach the target concentration were significantly longer at the shorter contact time, and unachievable without the static mixer. The dosages of scavenger required to reduce the H2S concentrations from 180 ppmv to 10 ppmv were much higher than theoretical dosages. The addition of water to the scavenger mixtures was found to increase the efficiency of the ethanolamine scavenger but decrease the performance of the methylamine based triazine. The importance of atomisation of the scavenger onto the fixed bed was reinforced by the dramatic reductions in performance associated with a lack of atomisation. The presence of CO2 had no significant impact on the scavenging efficiency but had a kinetic impact and reduced the time to achieve the target concentration.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling > Drilling Fluids and Materials (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper 2019-1016 OMC, โSulfur Removal on an FPSO: A Liquid-Redox-Process Case Study,โ by William I. Echt, Merichem, prepared for the 2019 Offshore Mediterranean Conference and Exhibition, Ravenna, Italy, 27-29 March. The paper has not been peer reviewed. Eni began producing oil reserves from the Aquila reservoir in the Adriatic Sea soon after its discovery in the early 1980s. As primary production decreased, a decision was made to begin enhanced recovery with artificial gas lift. With the play in deep water (815 m) and 46 km off the southern coast of Italy, a floating production, storage, and offloading (FPSO) vessel was needed. After a 5-year run, the Firenze halted operations in 2018 because of low oil production. The complete paper examines the decision to use hydrogen-sulfide- (H2S) removal technology, the cost of operation, and the unitโs availability over its lifetime. Introduction As the industry searches for reserves in ever-deeper formations, the requirement of contending with sulfur increases. Several H2S-removal technologies are available, including nonregenerative liquid scavengers (triazine-based), nonregenerative solid-bed absorbents, and the regenerative liquid-reduction/oxidation (redox) process. These technologies remove sulfur from associated gas streams and do not release them to the environment. The nonregenerative technologies are often referred to as scavengers. Process Evaluation During the initial design phase, several H2S-removal technologies were evaluated per the following criteria: Turndown capability H2S-removal efficiency Degree of operator involvement required Maintenance requirement and waste material produced Proven reliability in marine conditions The evaluation led to the selection of the liquid-redox process after it received the highest marks in four of the five criteria. Both liquid and solid H2S scavengers were considered as alternatives to the liquid-redox process for this installation. The considerations for each criterion are detailed in the complete paper.
Anyone who works in the oil and gas industry is aware of hydrogen sulfide (H2S) gas. This is a highly toxic gas that gives rise to โsourโ production. H2S is highly corrosive to many common materials used by the industry (e.g., mild steels), and there often are strict fiscal and technical limits placed on upstream oil and gas producers by the midstream and downstream operators. The origin of H2S can be authigenic (i.e., occurs in-situ and naturally in the reservoir, related to the biological origin of the organic matter that produces the crude oil and gas), or it can be caused by biological processes and the action of sulfate-reducing bacteria (e.g., during seawater flooding and contamination of the reservoir). The concentration range of H2S that occurs can vary from a few parts per million (ppm) to many tens of percent of the raw gas production. The range of concentrations that may be treated economically by chemical H2S scavengers is typically up to 5,000 ppm (0.5%). Higher concentrations may be treated by other means such as amine recycling unit sequestering systems. The industry has relied upon the triazine family of chemistry for several decades as the mainstay scavenger for H2S (originally patented in the 1990s), and the understanding of the application parameters and reaction byproducts has grown over the years. There is, however, still much to understand, and, even recently, several significant advancements have occurred, many focusing on some of the understood challenges of using triazine chemistry. The featured papers and suggested further reading summarize the current SPE literature state of the art for H2S scavenger research and development and have been selected to give readers a broad indication from both academia and industry around the world.
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper IPTC 20203, โEnvironmentally Preferable Smart Chemicals for the Oil and Gas Industry,โ by Prasad Dhulipala and Melanie Wyatt, Baker Hughes, and Charles Armstrong, SPE, Solvay, prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13-15 January. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. The oil and gas industry uses acids and oxidizers as polymer breakers in hydraulic fracturing, and triazene and glyoxal for hydrogen sulfide (H2S) mitigation. In addition to serving their intended purpose, however, these chemicals cause secondary effects such as nonspecific oxidation, acid corrosion, precipitation, and danger to oilfield personnel. This paper describes studies that confirm that enzyme-based, environmentally preferable chemistries can be used to break polymers and mitigate H2S in various systems. The biotechnology-based solutions also offer advantages such as meeting environmental regulations and reducing or eliminating secondary effects and health hazards associated with current chemical treatments. Complexities of Current Chemical Treatments Fluid for hydraulic fracturing operations usually consists of 99% water thickened with guar or derivatized guar polymers. After the highly viscous fracture fluid is placed into the fracture, the fracture fluid needs to be brought back from the proppant pack, leaving the proppant without damaging the conductivity. This is accomplished by thinning the viscous fluid pumped into the fracture into a Newtonian fluid with a very low viscosity. Chemical breakers reduce the molecular weight of guar polymer by cutting the long polymer chain. As the polymer chain is cut, the fluidโs viscosity is reduced. Oxidative breakers react rapidly at elevated temperatures and cause the polymer to break prematurely, leading to loss of viscosity and reduction in proppant transport. Encapsulated oxidative breakers have seen limited use because of rapid degradation that causes premature reduction in fluid viscosity. Additionally, oxidizers react nonspecifically with any oxidizable material, including metals and formations. Oxidizers also pose a significant safety hazard. Reservoir souring is another major problem in oil and gas operations and is estimated to cost $120 billion per year. Reservoir souring occurs as a result of injecting sea water into hydrocarbon reservoirs, causing contamination of fluids with microbial population. Souring decreases production asset value and increases cost. In worst-case scenarios, it necessitates shutting off the wells. H2S scavengers provide a cost-effective alternative for removing H2S when amine treatment is not possible or cost-prohibitive. Triazines are water-soluble H2S scavengers that have been used successfully for many years. They add a minimum amount of nitrogen and reduce H2S instantly. Recent advances include development of greener quaternary amine compounds (quat) and non-quat products, better delineation of a triazine-based scavenger mechanism, formulation of newer combinations, and the invention of newer classes of scavengers such as unsaturated aldehydes, hydroxy alkyl or alkyl oxides, or azodicarbonamides that are resistant to pH and other changes in the reservoir.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.56)
Desorption columns for hydrogen sulfide removal from crude oil by stripping with the hydrocarbon gas were tested in the two Tatneft PJSC high-sulfur oil treatment plants, the Kuakbash and the Kama-Ismagilovo. This paper presents findings from the tests, challenges of the new technological approaches and the solutions. To address the problem of forming of a large amount of condensate and gas in condensate tanks (drips), recirculation and orificing technologies were used. The objective of this work was to raise the quality of stock-tank oil as regards the residual H2S content to meet the requirements of standard GOST R 51858-2002 in the most cost-efficient way. Chemical H2S scrubbing techniques that have been used in the Oil and Gas Production Department Leninogorskneft oil production facilities are rather costly and still do not allow to meet the state standards (GOST) requirements. It has been found that stripping high-sulfur oil with the Devonian hydrocarbon gas in the desorption column was the most effective way to remove H2S from crude oil in the Kuakbash and Kama-Ismagilovo oil treatment plants. However, increase of pressure in the column worsened the quality of crude oil treatment, caused dilution of lubricating oil in the compressor, and led to forming of a large amount of condensate from the stripping gas in drips. To solve these problems, the second stage of separation was introduced in the Kuakbash oil treatment plant, an air cooler was included in the crude oil treatment system to decrease gas temperature downstream of the column and slow down condensing of heavy hydrocarbons upstream of the compressor station; gas recirculation and gas orificing technologies were realized in the Kama-Ismagilovo and the Kuakbash oil treatment plants, respectively, to minimize (exclude) condensate forming in drips of pressure pipelines. These technological solutions made it possible to improve the quality of the stock-tank oil to comply with the GOST requirements.
New, Non-Corrosive, Non-Nitrogen Containing H2S Scavenger for Use in Predominately Oil and Gas Systems
Ramachandran, Sunder (Baker Hughes, a GE Company) | Lehrer, Scott (Baker Hughes, a GE Company) | Chakraborty, Soma (Baker Hughes, a GE Company) | Leidensdorf, Jeremy (Baker Hughes, a GE Company) | Panchalingam, Vaithilingam (Baker Hughes, a GE Company) | Ahroor, Danika (Baker Hughes, a GE Company)
ABSTRACT Hydrogen sulfide (H2S) is often present in oil and gas production fluids. The gas is toxic, corrosive to mild steel and induces localized sulfide corrosion cracking (SCC) in materials with susceptible metallurgical properties Treatment with H2S scavengers can enable the use of less-expensive low alloy carbon steel materials. Triazines and glyoxal are commonly used H2S scavengers in oil and gas production. In some instances they are used to reduce H2S levels to safe values and make the installation safer. There are problems with the use of trazine and glyoxal. Triazines especially Monoethanol amine Triazines (MEA-Triazine) are well used but have some problems with solid formation and creation of corrosion problems in refineries MEA-triazine reacts with H2S to create an insoluble reaction product known as amorphous diathiazine that is difficult to remove. Sometimes refineries ban or discount crude oil that contains triazine. The reason they do this is that the presence of triazine in crude can cause downstream corrosion problems in crude distillation overhead lines and crude unit. Glyoxal is a hydrogen sulfide scavenger that does not contain nitrogen. This product does not cause corrosion problems in refineries due to formation of amine salts. Glyoxal though has a low pH that can result in corrosion at any location where oil and water can separate and glyoxal causes the water phase to have a low pH.. Due to the problems with nitrogen containing H2S scavengers, and glyoxal, some customers have asked for non-nitrogen containing, non-corrosive H2S scavengers. This paper presents laboratory results on a new, non-corrosive, non-Nitrogen containing H2S scavenger. The new scavenger has a pH in the range of 7.5 to 8.5 that does not form problematic solids on reaction with H2S. The product has been used in towers and direct injection in wet gas systemsThe product is not water-based and can be used in dry oil and dry gas and condensate systems. The successful use of this product in wet systems has been described in previous work but is included for completeness in this paper. Some of the more successful field results include application of the product to a dry oil system and a dry gas and condensate system. This is useful for cases where the operator wishes to decrease the H2S content of a dry oil and dry gas and condensate pipeline without introducing water in the application. This is not possible with products that contain water.
- Asia (0.68)
- North America > United States > Texas (0.48)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.70)