Sour gas is natural gas or any other gas containing significant amounts of hydrogen sulfide H2S).Sour gas reserves are historically left undeveloped because of the technical challenges and costs involved in their extraction and processing. Natural gas that contains more than 4 ppmv of hydrogen sulphide (H2S) is commonly referred to as "sour". This is because the odour of hydrogen sulphide gas in air at very low concentrations is similar to that of rotten eggs. Significant quantities of natural gas resources around the world are known to contain H2S. These have been difficult to produce in the past because of the tendency for sour gas to cause corrosion and sulphide stress corrosion cracking, particularly in pipelines.
Recently, global climate change and air quality have become increasingly important environmental concerns. Consequently, there has been a rise in collaborative international efforts to reduce the concentration of greenhouse gases and criteria pollutants. Greenhouse gases include carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O), occurring naturally and as the result of human activity. In addition, criteria pollutants (1970 amendments to the Clean Air Act required EPA to set National Ambient Air Quality Standards for certain pollutants known to be hazardous to human health) include emissions of nitrogen oxide, sulfur dioxide, carbon monoxide, and total unburned hydrocarbons. International and national governments are implementing more regulations on air emissions.
Consequently, there has been a rise in collaborative international efforts to reduce the concentration of greenhouse gases and criteria pollutants. Greenhouse gases include carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O), occuring naturally and as the result of human activity. Criteria pollutants include emissions of nitrogen oxide, sulfur dioxide, carbon monoxide, and total unburned hydrocarbons. International and national governments are implementing more regulations on air emissions. Drilling contractors can play an important role in environmental stewardship by reporting carbon emissions from drilling operations, eliminating redundant emission measurements, and leading the industry in efforts to reduce these emissions.
Natural gas is a mixture of many compounds, with methane (CH4) being the main hydrocarbon constituent. When natural gas is produced from an underground reservoir, it is saturated with water vapor and might contain heavy hydrocarbon compounds as well as nonhydrocarbon impurities. In the raw state, natural gas cannot be marketed and therefore must be processed to meet certain specifications for sales gas. Additionally, it might be economical to extract liquefiable hydrocarbon components, which would have a higher market value on extraction as compared with their heating value if left in the gas. Gas treating facilities, therefore, must be designed to convert a particular raw gas mixture into a sales gas that meets the sales-gas specifications, and such facilities must operate without interruption.
Hexahydro-1,3,5-tris(2-hydroxyethyl)-s-triazine (MEA-triazine) is by far the most ubiquitous H2S scavenger used globally and occupies at least 80% of the available oilfield market. While almost the perfect scavenger in terms of kinetics and H2S uptake, this product does suffer from a number of undesirable effects which are usually tolerated or managed by various engineering modifications. For example, pH elevation causes scaling issues, deposition of intractable polymeric solids and increased ethanolamine load in crudes entering a refinery are some of the most prominent.
A new scavenging technology has been developed that offers an alternative to triazine. The guiding principles in the design of this technology were to achieve, equal or better scavenger efficiency compared to triazine, equal or better reaction kinetics compared to triazine, "best in class" solids control, minimal pH impact, cost competitive with triazine, no impact on fluid separation and minimal refinery impact. A family of products have been developed which are multicomponent systems, each having a designated function. The active scavenger is based upon a "latent" or hidden form of a small molecule scavenger (SMS), similar to a protecting group strategy in organic synthesis. The steady state active SMS concentration remains very low in the initial product, but it is released upon demand when it encounters hydrogen sulfide in its operational environment. The SMS release can be greatly enhanced using a suitable catalyst or synergist, over the base scavenger/carrier system, which enables a more efficient use of the base molecule. The quality and exact nature of the spent fluid is critically important to H2S scavengers and much effort has gone into the control and handling of the byproduct. High sulfur scavenger byproducts are almost always solid in nature and can cause numerous operational issues. MEA triazine has such a problem and polymerization of the initially formed monomeric dithiazine to amorphous dithiazine is one of the drivers to develop an alternative as is presented here.
This new suite of products has undergone successful field trials in both gas contact towers and direct injection applications. Some challenges have also arisen, as expected with any innovation, in other application areas and environments where unexpected issues have been encountered. An honest and informative account of the design, development, properties, field trial results and future direction for this exciting new technology are discussed as well as a critical evaluation against the aforementioned triazine industry benchmark.
The objective of the paper is determining the effects of reducing the sulfur content in diesel on its properties, specifically lubricity and electrical conductivity, and the optimal injection rates of lubricity and anti-static chemicals when producing maximum 10 ppm sulfur diesel product from 50/50 Arab Light and Khurais Crude Feed. The optimal injection rates should ensure that the 10 ppm sulfur diesel product will achieve the required product specifications in terms of lubricity and electrical conductivity while maintaining an economically sustainable consumption of the injected chemicals. The test run commenced with collecting a 10 ppm diesel reference sample from the refinery diesel rundown before injecting the chemicals. Then, the chemical injection of both lubricity and antistatic improvers was commenced. The injection rates of the lubricity and antistatic improvers were adjusted via the pump stroke once per day. After that, two samples of the diesel product rundown stream had been collected. The daily samples were analyzed for their lubricity and electrical conductivity by performing the test procedures ASTM-6079 and ASTM D-2624 respectively. the test results for the lubricity test run indicates that the ideal injection rate for the lubricity improver chemical is at 70.0 ppm where the lubricity specification of Max. 460 μm is met with optimal consumption of the chemical. On the other hand, electrical conductivity results were always significantly above the 10 ppm sulfur diesel product minimum specification of 50 μS/m regardless of the conductivity improver chemical injection rate. At the lowest turndown of the pump of 0.49 ppm injection rate, the lab results fluctuated between 280 μS/m and 780 μS/m. Although the product conductivity specification had been met in the test trial, the conductivity improver chemical was stronger than required. Therefore, another alternative chemical that is compatible with the equipment of the injection system may be considered.
Langé, Stefano (TOTAL S.A. 2 Place Jean Millier) | Zhao, Jing (TOTAL S.A. 2 Place Jean Millier) | Cadours, Renaud (TOTAL S.A. 2 Place Jean Millier) | Weiss, Claire (TOTAL S.A. 2 Place Jean Millier) | Bernadet, Mikael (SOBEGI Induslacq) | Caetano, Michel (SOBEGI Induslacq) | Layellon, Lise (SOBEGI Induslacq)
This paper presents how the optimization of the solvent composition provides significant OPEX reduction and simplifies process management.
Removing mercaptans from natural gas is becoming a tough work for operating companies due to the tightening of commercial specifications for sulfur-containing molecules in the final products. Beside this, about 40% of the known gas reserves are sour; some of them contain H2S and mercaptans. To commercialize these gas fields in a profitable way, smart process solutions focused on energy efficiency are needed. Classical gas sweetening units are based on chemical absorption by means of aqueous alkanolamines to remove CO2 and H2S from natural gas. These solvents have limited mercaptans removal capacity, requiring supplementary removal processes. This has a negative impact on the overall gas processing costs.
To face this challenge, TOTAL has developed a new series of hybrid solvents able to remove, in a one- step operation, CO2, H2S and mercaptans. Process performances can be improved without plant modification. The first solvent formulation was based on DiEthanolAmine (DEA) and was implemented in the sweetening units of the Lacq plant (France), demonstrating the benefits of the new hybrid solvents at industrial scale.
DEA solvent is a widely used and easy-to operate/monitor solvent. However, DEA has the drawback to be sensitive to chemical and thermal degradation. Moreover, DEA regeneration is quite energy demanding.
To overcome these problems, the amine components have been changed. The choice of new components is driven by following characteristics: good solvent stability, low regeneration energy demand, high CO2 and H2S removal efficiency.
A mixture of MethylDiEthanolamine and Piperazine (MDEA+PZ) has been adopted as the solution to replace the DEA based solvent. The choice has been made thanks to the good chemical stability of MDEA and the high performance of PZ as an activator to boost the rate of the absorption process.
This paper presents the operational feedback with this new formulation. The first benefit of the hybrid solvent formulated with MDEA+PZ is that it was implemented in the existing unit without plant modification. Other advantage is the improved chemical and thermal stability. This solvent swap allows to decrease the reboiler duty of the solvent regeneration, to reduce the chemicals consumption, while keeping the final product quality unchanged.
The benefits of the solvent swap will be supported by operating data collected before and after the solvent swap.
To meet the regulations on the emission of toxic gases such as carbon monoxide (CO) and Hydrogen Sulfide (H2S) from the Sulphur Recovery Units (SRUs), a high amount of fuel gas is burnt in the incinerator to oxidize them that increases the sulfur production cost and CO2 emissions. This study investigates the major reactions that cause CO emissions and recommends possible solution to mitigate its formation in the SRU. The SRU simulations were conducted using a well validated and detailed reaction mechanism that captures the chemistry of CO and Sulfur species in the Claus furnace. The Claus reaction mechanism, containing 290 species and 1900 reversible reactions for the oxidation of H2S and the formation and destruction of COS, CO, CO2, hydrocarbons, and CS2 was used for reactor simulations, which was validated successfully using industrial plant data and the experimental data from lab-scale setups. The process parameters were varied to find the set of conditions that minimize CO production in the SRUs. The CO production in Claus furnace occurred through the high temperature decomposition of CO2 and CH4 present in the acid gas stream. The production of COS occurred from the reactions of CO with sulfur. The inlet temperatures of the feed gas streams (air and acid gas) were varied systematically to observe their effect on sulfur recovery and emissions of CO, SO2, COS, and aromatics. Upon decreasing the furnace temperature (by decreasing inlet air temperature) from 1105°C to 1050°C, CO emission from the SRU decreased by up to 60%, while sulfur recovery efficiency increased by 0.2%. However, the emission of aromatics (mainly benzene) increased by 3.5 ppm, while the more detrimental toluene, ethylbenzene and xylene were completely oxidized. Thus, maintaining an optimal feed temperature was found to minimize CO emissions from the SRUs, while maintaining high sulfur recovery. The simulation results predict the cost-effective solutions of minimizing CO and SO2 emissions from SRUs through the variation in process parameters that will help in reducing the consumption of fuel gas in the SRU incinerator.
A significant portion of natural gas reserves around the world contain large quantities of sulfur species and carbon dioxide, which are often referred to as sour gas reservoirs. The IEA reports that more than 40% of the world's gas reserves are sour, with the number increasing to 60% for Middle Eastern gas reserves. Sulfur species, such as hydrogen sulfide (H2S), are highly corrosive when mixed with water and toxic to biological organisms. Compounds such as SO2 and SO3, which are derived from direct sour gas combustion, are also highly corrosive when mixed with water at the condensation temperature of sulfuric acid. Therefore, removal of H2S to trace levels from natural gas is typically considered as the first step of the utilization of sour gas for power generation. This paper presents a novel method which enables sour natural gas to be directly burned for power generation without pretreatment. Oxidized sulfur compounds are captured by limestone in the combustion process to eliminate downstream sulfur corrosion. The desulfurized flue gas then goes through a solids removal process before entering a gas turbine or a turbine expander for power generation. A steam cycle is used for waste heat recuperation from both the turbine exhaust stream and the solids stream to improve the cycle performance. Both air-combustion and oxy-combustion configurations were investigated and modeled using Aspen Plus. The design conditions of each cycle are within the operating envelope of commercially available equipment, including compressors, turbines and heat exchangers, enabling near-term deployment of the presented system. Aspen modeling results show the range of efficiency percentages for different cycles is from the low 40's to the low 50's on a Lower Heating Value (LHV) basis. Without pretreatment, the heating value of sulfur in the sour gas and the heat released from the limestone scrubbing process can be fully utilized for power generation, thus improving the cycle performance. Economic analyses estimate that the baseline air-combustion sour gas system with a conservative estimated Capex ($2142/kW) is 41% cheaper than NGCC in 2011, and is about 28% cheaper than advanced NGCC in 2022 on a simplified Levelized Cost of Electricity (LCOE) basis. The LCOE of the oxy-combustion sour gas system is estimated to be 53% lower than advanced NGCC in 2022 when the revenue from CO2 and Argon sales is taken into account. Therefore, the novel untreated sour gas combustion system presented in this paper enables the petroleum and power industries to use sour gas for power generation more efficiently and cost effectively, even with full carbon capture.
Benzene, Toluene, Ethylbenzene and Xylene (BTEX) present in feed gases to Sulfur Recovery Units (SRU) cause frequent catalyst deactivation. BTEX can be oxidized at the recommended temperatures above 1050°C. High temperatures are achieved through feed preheating and co-firing acid gas with fuel gas. However, temperatures above 1050°C is not required when BTEX concentration is low. A multi-objective optimization approach is deployed to minimize feed preheating temperature and fuel gas co-firing, while maintaining high BTEX destruction. A well validated model for Claus furnace from previous studies was used for furnace simulations. Claus furnace was modelled using Chemkin Pro, while catalytic section (including condensers, re-heaters and incinerator) was modelled using Aspen Hysys (Sulsim). MATLAB was used as a platform to link Chemkin Pro with Aspen Hysys. Optimization was performed in MATLAB using genetic algorithm. The objectives of optimization were to 1) Maximize sulfur recovery, 2) Minimize fuel gas consumption to furnace, 3) Minimize air and acid gas preheating temperature. As a constraint, total BTEX at waste heat boiler outlet (WHB) was maintained below 1ppm. The optimization range for fuel gas flow rate was from 29 to 2034 nm3/hr, air temperature from 180 to 360°C and for acid gas temperature, 180 to 230°C was considered. The feed properties and physical dimensions of SRU were obtained from an industrial SRU plant. Results show that furnace temperature of 1028°C needs to be maintained for maintaining BTEX destruction for the given feed condition examined. Thus, fuel gas co-firing can be reduced from base case value of 1773 nm3/hr to 29 nm3/hr, while air preheating temperature can also reduce from 325°C to 223°C. This can assist in reducing operational costs in sulfur recovery units considerably. The present work predicts the ideal conditions for BTEX destruction in SRUs based on inlet feed conditions. This approach can be used to seek favorable means of optimizing Sulfur recovery, decreasing fuel gas consumption in sulfur recovery units to reduce operating cost.