The paper record.

Rising hydrogen sulphide levels from souring reservoirs and high-sulphur crude oils are turning sulphur recovery units into major throughput bottlenecks in both gas plants and refineries. Filip Cejka of Bryan Research & Engineering presents oxygen enrichment as a practical debottlenecking strategy, with water electrolysis - especially alkaline water electrolysis and, to a lesser extent, solid oxide electrolysis - offering promising oxygen supply options.

Neutralization with caustic in amine systems has long been a debated topic and there is no shortage of experts weighing in on the pros and cons. This paper will revisit the historical practice of intentionally adding caustic to amine with the purpose of improving performance and reducing corrosion by "neutralizing" Heat Stable Amine Salts (HSAS) which have accumulated in the amine. The paper will briefly cover introductory concepts including electrolyte reactions, corrosion reactions, chelation, and the relationship between soluble iron and corrosion rate. A series of simulations will be used to demonstrate the effects of heat stable salts on the ionic speciation of amine, how adding NaOH affects the speciation, and what happens when too much NaOH is added to an amine system. Plant data from several amine units will be presented to show the effect of neutralization on soluble iron concentration as well as the impact of overneutralization on lean loading We will also use simulations to explore other relevant topics including the impact of neutralization on ionic strength / activity coefficients, and on potential volatility of HSS species such as acetate and formate in the regenerator reboiler.

Measuring, calculating, and understanding emissions from water tanks is accomplished in various ways, but is increasingly consolidating into an industry standard. This work is meant to build from previous studies, share industry experience, and detail the procedure that most accurately represents emissions from water tanks and satisfies regulatory requirements. This includes addressing the "1% rule" and the various interpretations of its implementation. The Sample + Model approach detailed here leverages the strengths of laboratory analysis with the power of thermodynamic modeling to contribute a well-informed emission calculation to industry, regulators, and the community.

Most users of ProMax have always been at the forefront of operating, designing, researching, and troubleshooting process units in the sulphur value chain. However, more recently, with the emergence of net zero initiatives by international conventions and governments (e.g. the Paris agreement), the push for decarbonisation in our industry has been on the rise. This article, published in the July-August edition of the SULPHUR magazine, takes a look at the bigger picture and examines ways to reduce carbon footprint in sour gas facilities.

In this technical paper titled, "Carbon Capture Technology Evaluation & Design Using Process Simulation", ProMax was used to conceptualize, select, design, and integrate components for a representative post-combustion carbon capture unit. This presentation covers a data driven analysis of comparing various solvent choices (physical vs chemical; primary vs secondary vs tertiary amines; MEA vs AMP/PZ) as well as additional key considerations (SOx removal, flue gas pre-cooling, packed vs trayed contactors, water wash systems, reboiler duty etc) that go into the end-to-end evaluation and overall robustness of a for LP carbon capture system. This presentation hopes to serve as a guideline and reference for process engineers looking to design and/or optimize such a unit.

The refinery amine unit regenerator is a significant consumer of energy, and with so much emphasis currently placed on carbon intensity, there is an increased interest in the performance of regenerators. The primary function of the amine unit regenerator is to reverse the acid gas absorption reaction, and by doing so provide adequately-stripped lean solvent for the amine absorber(s). However other often-minor considerations can also influence regenerator energy requirements. In this paper we focus on two case studies that highlight regenerator operation. By analyzing the conditions in the regenerators with the PROMAX® amine simulator, we examine performance and consequences when the systems operate near low-energy and turn-down boundaries. Both Cases are set in refinery primary treating systems. The first case explores the consequences of a step change in operating conditions resulting from a refinery crude diet change. The second case reveals effects of a loss of lean/rich exchanger performance. "Rules of Thumb" for managing reboiler duty are considered for both cases.

Foaming is a major operational occurrence seen in gas sweetening units, causing production losses, off-spec product, solvent losses, equipment corrosion and excessive consumption of anti- foam chemicals. Foaming can therefore shutdown an entire unit if mismanaged. This paper details a multi-layered bulletproof strategy to manage foaming while operating and designing ultra-sour gas sweetening units. Process simulation models of an operational amine unit at ADNOC Sour Gas (ASG) were built to showcase the positive impacts of each of these recommendations on the performance of the unit.

Ammonia is one of the most produced chemicals in the world, with a production of about 150 million metric tons a year. It is critical for improved yields in modern agriculture as well as a chemical feedstock to various other processes. Today, Steam Methane Reforming (SMR), which uses fossil based natural gas as its feedstock, is the most widely used method for ammonia production. In this process, the natural gas is used to produce hydrogen, which is then reacted with nitrogen from the air to form ammonia. This technology generates a significant amount of greenhouse gases (GHGs), which has led to proposals for new processes that lower the carbon intensity of ammonia production while still maintaining process efficiency. One approach for reducing GHGs from the conventional SMR process is either sequestration of vented CO2, carbon capture from process flue gas, or a combination of the two. These methods have sometimes been dubbed "Blue Ammonia". Another approach, sometimes called "Green Ammonia", utilizes water electrolysis as its source of hydrogen. The use of water electrolysis allows water and renewable sources of electricity, such as wind and solar, to supplant natural gas as the feedstock for the required hydrogen production. Two categories of electrolysis units include alkaline water electrolysis (AWE) and polymer electrolyte membrane electrolysis (PEM). While the SMR process can use air as its source of nitrogen, the AWE and PEM based technologies require pure nitrogen to be available. A third category of electrolysis, solid oxide electrolysis (SOE), can also generate pure hydrogen from renewable electricity, but unlike AWE and PEM, does not require pure nitrogen. SOE also provides additional avenues of heat integration between hydrogen production and ammonia synthesis that is lacking from the other electrolysis technologies. A comparison is made between the various newer technologies to a conventional SMR system using a steady-state simulator. This comparison includes the configuration and requirements of each system, as well as each system's carbon intensity and power requirements per ton of ammonia produced.

Most process engineers consider gas plant economics only in terms of minimizing utilities and maximizing product, and they are leaving money on the table because of it. One aspect that should play a major role in optimization analysis, but commonly gets overlooked, is considering how contract structures with upstream producers and downstream markets affect gas plant profitability. Highest recoveries and lowest utilities are not always the true economic optimal points, especially when under fixed recovery contracts. A more wholistic approach considers producer contract structures and incorporates them into an overall economic function of the plant. These factors, integrated with a process simulator, show the true economic optimal operating conditions. To demonstrate the importance of process engineers understanding and capitalizing on producer contracts, this approach is applied to scenarios in which the contract structures would be a key factor in determining the optimal operating conditions of a gas plant.

Absorbers absorb. Strippers strip. It is what they do. But what happens if they don't? In discussions of amine contactors, the statement "Under the right conditions, stripping can occur" is sometimes heard. This has been said often enough that some people accept it as fact, while others dismiss the idea. We investigated this claim and did find that during co-absorption of both H2S and CO2, there can be movement of one of these two species from the amine into the vapor, and established conditions that cause it. As an example, we found that DEA can release H2S in the when the feed gas also contains CO2. This paper will show when stripping cannot occur, explore potential causes of stripping in an absorber, and give examples of conditions that cause stripping.

Knowledge about the behavior of temperature bulges in amine systems is of considerable importance, especially if instrumentation does not allow the bulge to be directly monitored. A high temperature bulge can create corrosion or degradation issues while the unit otherwise performs as intended. As instrumentation often does not allow direct monitoring of the temperature bulge, the operator is left blind to the presence of a high temperature bulge, and the negative effects are allowed to continue longer than normally would be the case.

Maximum corrosion rates in hydrofluoric acid (HF) alkylation units occur when free acid phases reach 30 wt% water (H2O). Unfortunately, measuring the presence or composition of free acid phases on column stages is impractical. Bryan Research & Engineering's (BR&E) process simulation software, ProMax, can simulate HF alkylation and free acid phase composition in the isostripper to help refiners avoid corrosive situations. Using experimental data for HF/Hydrocarbon and HF/HO mixtures, BR&E tuned the relevant binary interaction parameters to match this system. The resulting Peng-Robinson Polar and SRK Polar thermodynamic packages accurately model the three-phase equilibrium and HF/H2O azeotrope in an HF alkylation process. Entrainment of HF within the hydrocarbons in the acid settler and internal acid regeneration provide routes for HF entry into the isostripper column. ProMax can show whether a free acid phase forms on an isostripper stage. Simulation analysis predicts HF/H2O compositions in the acid phase for subsequent assessment of corrosivity.

In the early 1990's, Chevron installed a new process to recover natural gas liquids (NGLs) from recycled CO2 in their Rangely Weber Sand Unit. The facility was designed based on a patent issued in June of 1988 (U.S. Patent # 4,753,666). The process, as claimed in the patent, used a refluxed distillation tower to produce an overhead stream virtually free of n-butane and heavier components and a bottoms stream containing the majority of the heavier components. Based on the success of the Rangley plant's operation, a similar facility was designed and fabricated by Dickson Process Systems and installed in Chevron's Mabee field near Midland, Texas.

In sour gas treating systems there are a number of potential side reactions that produce unwanted byproducts. These reactions depend on reactant concentrations, reactant absorption rates, temperature, kinetic rates and residence times. Appropriate prediction of the rate of these side reactions can give greater insight into the process, in terms of degradation rate and impact of operating conditions. Three reactions are examined in the context of a typical amine treating process: conversion of hydrogen cyanide to formic acid, hydrolysis of carbonyl sulfide in MDEA, and CO2 degradation of DEA. In this paper, we will explore the occurrence of these reactions throughout the process and the effect of operating conditions through the use of simulation.

Methanol is commonly injected into hydrocarbon fluids to inhibit hydrate formation. Bulk methanol removal from a hydrocarbon fluid often occurs through separators as it is processed. However, a small amount of methanol in a processing plant's feed can often result in high concentrations (greater than 1,000 ppm) in the natural gas liquid (NGL) product. This work evaluates several methods for removing enough methanol in the amine sweetening unit to meet NGL specifications. It also discusses strategies for preventing methanol buildup in the NGL by understanding the phase behavior through the entire plant. A complete model of the operating plant was created and compared to operating data to make impactful decisions for operating the plant. This paper shows that methanol concentrations in the NGL product can be reduced in the amine treating system by increasing the condenser temperature, increasing amine solvent circulation rate, decreasing the lean amine loading, decreasing stripper pressure, and purging some or all of the stripper reflux.

Elevated feed-CO2 levels decrease the maximum ethane recovery in GSP and similar demethanizer configurations. This can be attributed to two causes. First, as CO2 displaces methane in the feed, the feed tends to behave more like a richer gas, which tend to have decreased ethane recoveries. Secondly, the choice of column operating conditions is complicated by the tendency of high-CO2 feeds to form dry ice in the upper sections of the column, or in the feed or residue lines. This often requires a sacrifice of ethane recovery to avoid dry ice formation. However, by manipulating column operating parameters, namely the vapor and liquid split to the subcooler, the column operating pressure, and the inlet split to the reboiler, the CO2 concentration profile in the column can be tailored to avoid dry ice formation, while still maximizing ethane recovery. This paper explores the effects of adjusting these operating parameters with both lean and rich feeds.

It is not uncommon today for producers to introduce methanol into their hydrocarbon systems, either as a means of hydrate inhibition, as an additive blended with H2S scavengers, or for other purposes. While much of the methanol is recovered in liquid knockout drums, a portion of it remains in the natural gas or natural gas liquids where it eventually makes its way to downstream processing units.

Rules of thumb are often used for estimating emissions from Produced Water storage tanks, especially when entrained hydrocarbons are present. The rules of thumb are used because of difficulties in obtaining accurate compositional information as well as deficiencies in the estimation calculation methods. The different rules of thumb yield substantially different emissions estimates, and it is questionable whether some provide accurate estimates. A new process simulator-based method is presented that overcomes some of the sample analysis and calculation shortcomings. Predictions of the new method are presented that show the effect of hydrocarbon entrainment on produced water emissions. In addition, definitions and emissions estimates of some of the currently used rules of thumb are presented and contrasted with the new method.

Pressure relief valves are devices that protect equipment from excessive overpressure. In case of emergency situations, they should ensure a sufficient discharge of mass to reduce the pressure below the recommended pressure limits. The purpose of relief sizing is to determine the required area that can hold the required mass discharge from the valve under different overpressure scenarios. The discharged mass can be vapor, liquid, supercritical fluids or two-phase fluids. This article focuses on relief valve sizing methods for vapor phase and supercritical fluids at choked flow. The American Petroleum Institute (API Standard 5201,2) recommends basing vapor-phase sizing methods on an ideal gas flow assumption.1 This assumption has been addressed by several groups in the industry and may lead to high levels of deviation in cases of near critical and supercritical fluids 3,4. In the most recent version of API 520, a rigorous approach for calculating mass flux through the valves is introduced in addition to the existing, ideal gas based models.2 Furthermore, API Standard 520 suggests using a real gas isentropic coefficient calculation method as an alternative to the ideal gas specific heat ratio for sizing relief valves. This paper will compare different vapor and supercritical vapor vent sizing approaches and compare their performance against a rigorous model. The rigorous model performs many isentropic flashes using appropriate thermodynamic packages offered in ProMax7. The performance of each method is assessed through both pure component and mixture examples. In ProMax, a rigorous sizing method can be conveniently applied along with other alternative methods for API 520 sizing calculations7.

Historically, the concern of process engineers was the design and operation of plants to do primarily one thing, efficiently meet product specifications. In today's changing regulatory environment, there are additional concerns design engineers may neglect. These concerns include Volatile Organic Compounds (VOCs) and Hazardous Air Pollutants (HAPs) emissions as exceeding thresholds can limit throughput, increase liability to the operator, and add significant lead time to plant construction or modifications. A case study aimed at debottlenecking a large cryogenic gas plant is presented to investigate a legacy VOC and HAP issue as well as maximize overall plant production. The debottlenecking study focused on multiple amine sweeting units and their associated still vent emissions. Interestingly, methanol was found in surprising amounts in the still vent emissions. Control devices were assessed and subsequently installed to alleviate any future VOC and/or HAP issues and allow for increased production. The regulation of Green House Gases (GHGs) has changed significantly of late, with the likely outcome that treating will be performed in the field at "minor sources". Producers operating large plants already categorized as "major sources" of air pollutants must pay careful attention to these GHGs. A case study of a cryogenic gas plant is presented where increasing plant throughput was potentially bottlenecked due to emissions of CO2 in excess of Prevention of Significant Deterioration (PSD) permitting thresholds. A thorough analysis was performed of the plant to manage CO2 emissions while still maintaining product specifications. This allowed the operator to avoid a long, costly regulatory review and permitting process while still increasing production. With current GHG regulations likely to push gas treating into the field, sour gas streams may be the new bottleneck as SO2 emissions may curtail production due to the National Ambient Air Quality Standard (NAAQS) for SO2. Designers will need to begin evaluating the technologies best suited to work around this issue.

Removal of CO2 from natural gas is a necessary treating step before cryogenic processing. At the PTT Public Limited Company Gas Processing Plant 5, the wellhead gas has CO2 concentrations ranging from 19 to 23 mol%. This gas feeds an amine sweetening unit where most of the CO2 is removed. The sweet gas product is dried before entering a cryogenic demethanizer where ethane and heavier natural gas liquids are recovered. The demethanizer overhead reaches temperatures as low as -100 to -120 C. Thus to prevent CO2 freeze-out, the CO2 concentration in the sweet gas must be less than 900 ppm. This study focuses on optimization of the amine sweetening unit to increase throughput, provide adequate cold protection, and avoid corrosive operating conditions in the amine regenerator.

Since Abu Dhabi Gas Industries Ltd. (GASCO) is one of the largest gas processing companies in the world with a capacity of over 5.5 billion standard cubic feet of gas per day, optimization of its facilities is of great interest. As a part of this effort, GASCO has partnered with the Petroleum Institute and Bryan Research and Engineering, LLC to optimize its amine sweetening units. The first step in the optimization is to compare the latest electrolytic ProMax process simulation model to extensive operating data from the Habshan II facility to ensure good representation. The model is then used to optimize the Habshan II facility by analyzing the impact of the operating parameters such as circulation rate, amine concentration, temperatures, and reboiler duty on the plant performance. Finally, the outcome of the model is used to show the financial benefits to the plant.

Hydrocarbon processing systems and storage tanks are a significant source of volatile organic compound (VOC) emissions in the United States. Emissions rates from process units and tanks have historically been calculated individually for permit applications and at a single operating point once design engineering is complete. Now with EPA's new NSPS OOOO rule, operating companies must perform far more VOC emissions calculations than ever before to comply with increased reporting requirements. With more focus on the quantities emitted and possible control alternatives, there is more interest in using the emission calculation methods during the oil and gas production site design stage. More sophisticated modeling systems using chemical process simulators permit more accurate emissions estimation over a wider range of conditions and configurations. Recent advances in simulation interface technology permit automation of these modeling tasks for more efficient enterprise-wide reporting. 2014 GPA Conference Dallas, Texas

Part one of this series of papers (presented at GPA GCC 21st Annual Technical Conference in 2013) detailed various ways to optimize an amine sweetening unit, particularly sweetening units located in the Middle East (Slagle, 2013). Conditions in the Middle East are often more sour and warmer than other locations in the world. Part two expands on the work completed in part one, focusing on the impact of choices made for the sweetening section on the sulfur recovery unit, while detailing ways to optimize the entire process. Various aspects of the sulfur recovery unit design are impacted by the amine sweetening unit design. The influence amine sweetening technologies have on sulfur recovery units is explored, along with competing sulfur recovery options. The study details choices engineers must make when deciding the number of Claus beds, adding a tail gas treatment unit, using a selective versus non-selective amine and other essential variables.

The recent abundance of natural gas in widespread locations of the US has resulted in many resources being remote or stranded, creating the need for economical options for moving those resources to market. In many cases the gas is ethane-rich resulting in a need for new ways to monetize an otherwise low value ethane product. The current market price for ethane, in particular, is well below historical values and projections for the future indicate that this market condition will persist. Synfuels International, Inc. has developed a process for converting natural gas and light hydrocarbons to a high value, easily transportable gasoline product and, thereby, substantially increasing the value of the product. The process has great returns with payouts of about 2-3 years for ethane and about 3-4 years for natural gas streams of 15 - 20 MMSCFD and larger. The process concept and economics will be discussed.

Highly sour gas is an increasingly viable gas to treat and process in the Middle East. This paper details the optimization methodology necessary when operating or designing a highly sour gas plant at high pressures and temperatures, more commonly seen in the Middle East. The study explores DGA®, DEA, MDEA and MDEA + piperazine when selecting the amine solvent to use. It also shows the steps taken to determine the correct operating conditions for high pressure, high temperature and highly sour environments. A similar unit's operating data is used to create a base case for comparing various process enhancements. The study shows this particular unit may be able to save roughly 50% - 75% of its steam consumption by switching from 35% DEA to 50% MDEA or 70% DGA®.

This is Part I of a series of papers detailing a method to optimize a gas plant, while being thoughtful of downstream implications. Amine sweetening units are often at the front end of the gas plant and pose significant design and operation challenges to downstream operations. This paper compares DGA®, DEA, MDEA and MDEA + piperazine when selecting the amine solvent to use. It also shows the steps taken to determine the correct operating conditions for high pressure, high temperature and highly sour environments. While MDEA is routinely lauded for selectively removing H2S, this paper shows the selectivity is greatly diminished in these conditions and that DGA® may be the more appropriate solvent.

Natural Gas processing plants are an essential part of the energy industry, providing clean burning fuels and valuable chemical feedstock. The importance and complexity of gas processing plants have increased over the years, leading to improvements in energy efficiency and integration with petrochemical plants. These improvements are aided by the use of computer simulation models as tools for designing, troubleshooting, and optimizing gas treating plants. This work discusses the major optimization techniques based on the Benfield HiPure process at Abu Dhabi Gas Liquefaction Company Limited (ADGAS) and the use of a process simulation tool, ProMax®. At ADGAS' Train 3 plant in Das Island, high pressure natural gas containing 6 to 7 mole % acid gas first comes into contact with a 30 weight % Potassium Carbonate (K2CO3) solution promoted with 3 weight % Diethanolamine (DEA). The gas is then contacted with a 20 weight % DEA solution downstream. The results from the simulations show a close match with the plant operating data. The simulation model was then used to explore the effect of changes in process parameters on ADGAS' plant performance.

Bryan Research and Engineering, LLC (BRE) has developed an online, equipment performance monitoring application for radial turbo-machinery in cryogenic gas plants. The application works by capturing process measurement data in real-time and placing it in the ProMax® simulator for analysis. The modeling capabilities of ProMax are then leveraged against a new, empirical representation of momentum transport to deliver actual versus target performance indicators, such as efficiency, head, and power at off-design conditions. The results of the performance indicators are then returned to a data historian and a customizable display is used to monitor the performance of the turbo-machinery from anywhere on the network. As a result, engineers and operators now have the ability to make informed process decisions based on equipment performance adjusted for off design conditions. This paper highlights the application and its benefits using a case study with real-time data from a cryogenic gas train.

Achieving specifications given by customers, including pipeline-operating companies, LNG storage facilities, and gas-processing plants requires the removal of CO2 and H2S from natural gas. It is also becoming more important to meet environmental regulations set by national and local governments. This paper summarizes a study which compares the Benfield HiPure-LNG Train of Abu Dhabi Gas Liquefaction Company Limited (ADGAS) sweetening plant to other sweetening processes using the modeling software ProMax®. Natural gas from the gas reservoirs, containing about 6-7 mole% acid gas, first comes into contact with hot potassium carbonate (30 wt% K2CO3) promoted with diethanolamine solution (3 wt% DEA), and finally with 20 wt% DEA solution. The simulation proved to predict the plant operating data accurately. Subsequently, additional alternatives to the Benfield HiPure process were investigated as potential options for replacement, including MDEA, MDEA/piperazine, and MDEA/DEA mixtures. The activated MDEA (50wt% MDEA + 3wt% PZ) with a two-stage flash is the best alternative, with a 36% decrease in the reboiler duty. This paper shows the possibility of shutting down the potassium carbonate section of the sweetening train and swapping the DEA solution in the immediate downstream unit for a mixed amine in order to reduce operating costs while continuing to meet the treated gas specifications. Preliminary results are presented here.

The removal of CO2 and H2S from natural gas streams is a crucial step for the Liquefied Natural Gas (LNG) industry. Since its inception, ADGAS (Abu Dhabi Gas Liquefaction limited) has been employing the Benfield HiPure process in its LNG plant in Das Island to purify sour natural gas to ultra-sweet specifications before it is compressed to produce LNG. This work compares the technical and economic performance of some simple amine-based processes to the Benfield HiPure process used in ADGAS LNG units. These process alternatives are evaluated and assessed based on the product purity, energy consumption and overall economic performance. Simulation results using the simulator ProMax clearly underpin the possibility of replacing the Benfield HiPure process with amine-based processes that achieve the same level of gas purity but with a better economics. Processes using mixed amines such as MDEA/DGA and MDEA/DEA prove more economically viable with a 50% reduction in capital costs and 20% and 48% savings on the stripping cost and the annual power needed for the solvent circulation respectively. Therefore, the prospect of shutting down the potassium carbonate section and retrofitting the DEA section to MDEA/DEA or MDEA/DGA appears very promising, allowing ADGAS to decrease operating costs and possibly increase capacity.

The design and optimization of separation processes is carried out using process simulators which utilize various calculation approaches. Two techniques which are widely used for modeling distillation are the ideal stage model and the mass transfer model. The ideal stage model is relatively simple, but requires an overall efficiency for trays or a height equivalent of a theoretical stage for packing. The mass transfer model is significantly more computationally intensive and relies heavily on empirical equations for properties such as diffusivity, mass transfer coefficients and interfacial area. The primary emphasis of this paper will be on the application and comparison of the ideal stage and mass transfer models to systems with and without chemical reactions such as amine treating, glycol dehydration, reactive distillation and hydrocarbon separation columns. The advantages and disadvantages of each method will be discussed along with recommended guidelines for their application and use.

Natural Gas processing plants, an essential part of the energy industry, provide one of the cleanest-burning fuels and valuable chemical feedstock. The importance and complexity of gas processing plants have increased over the years to increase their energy efficiency and their integration with petrochemical plants. The advantages of computer simulation models as tools for designing and troubleshooting gas treating plants is increasingly obvious. This paper will discuss the major problems faced in operation of the Benfield HiPure process at Abu Dhabi Gas Liquefaction Company Limited (ADGAS) and the use of a process simulation tool, ProMax®, to investigate and suggest ways of overcoming some of these problems. At ADGAS' Train 3 plant in Das Island, high pressure natural gas containing 6 to 7 mole% acid gas first comes into contact with a 30 weight % Potassium Carbonate (K2CO3) solution promoted with 3 weight % Diethanolamine (DEA). The gas is then contacted with a 20 weight % DEA solution downstream. The results from the simulations show a close match with the plant operating data. The simulation model was also used to provide physical insight on how the changes in process parameters can affect ADGAS' plant performance, so as to suggest ways of improving or avoiding some these changes.

Hydrocarbon liquid dropout can cause a number of problems in gas transmission lines, including increased pressure drop, reduced line capacity, and equipment problems such as compressor damage. To avoid liquid dropout, most current operating specifications for gas transmission lines require that the lines be operated above the hydrocarbon dew point (HDP) or cricondentherm hydrocarbon dew point (CHDP). The HDP may be determined either by direct measurement such as the Bureau of Mines chilled mirror method or by calculation using an equation of state (EOS) with a measured composition. This project (GPA Project No. 081) was undertaken to determine a practical hydrocarbon dew point specification allowing small amounts of liquids that have no significant impact on operations. Results from the project show that 0.002 gallons of liquid per thousand standard cubic feet of gas (GPM) has a negligible effect on pressure drop and should not disrupt pipeline operations. Calculation of an accurate HDP from a GC analysis such as typically available at a custody transfer point may be useful but is highly dependent on the characterization of the heavy fraction. An extended analysis of the heavy fraction is best. However, an empirical method has been developed to predict the C6, C7, C8, C9 and heavier composition when only a lumped C6+ fraction characterization is available.

Sour water strippers are common in gas processing facilities, sulfur recovery units, wellhead facilities, and refinery applications. Understanding the variables allows engineers to better optimize the initial design and operation. This paper reviews options for sour water stripper configuration and presents a method to optimize stripper operation by finding the most efficient operating parameters. Options investigated include: single or double column for increased product purity; addition of acid or caustic for improved performance; refluxed or non-refluxed columns to mitigate water in the overhead gases; condenser or pump-around and their effects on overhead composition; reboiler, direct steam injection, or a combination of these and the effect they have on corrosion concerns. In addition, optimization of the steam rate is investigated. Overall stage efficiency for trayed strippers, HETP for packed strippers and individual component efficiencies are discussed based on available sour water stripper operating data.

This paper will focus on the hydrate formation conditions for acid gas mixtures commonly found in acid gas injection systems. Many studies have analyzed the hydrate and solid formation temperatures of CO2 systems. However, very little is known about hydrate conditions in varying acid gas mixtures as experienced in many injection systems. Herein, the available published data will be presented and compared with predictions from the process simulation software, ProMax ®. In particular, the hydrate conditions for both saturated and under-saturated systems will be explored for comparison on these injection systems.

Many "rules of thumb" are widely used in the design and operation of amine sweetening units. These rules have been developed over the years and most engineers accept them even though many have little familiarity with how important they may or may not be. Few ask why we have these rules, how absolute they are, and whether the rules have any flexibility. In this paper, several of these rules are described and evaluated for their usefulness and necessity using parametric studies with a steady-state process simulator. The rules evaluated include the 5 C temperature approach in the absorber, the 0.12 kg/L specification for reboiler steam, the 99C lean/rich exchanger outlet temperature, and the regenerator pressure/reboiler temperature guideline. Although these four rules of thumb are excellent starting points, none of them represent optimum conditions for all cases and, depending on the situation, violating these rules could offer considerable advantages to process efficiency. Every situation is different and requires a thorough investigation as to whether changes to these set points are beneficial and whether these benefits offset any additional risks.

Recently higher gas prices and improved drilling technology have spurred shale gas drilling across the US. Some of the more popular areas are the Barnett, Haynesville, and Fayetteville shales in the South and the Marcellus, New Albany, and Antrim shales in the East and Midwest. These plays represent a large portion of current and future gas production. But all shale gas is not the same, and gas processing requirements for shale gas can vary from area to area. As a result, shale gas processors must be concerned about elevated ethane and nitrogen levels across a field. Other concerns are the increased requirements of urban gas processing. In addition, the rapid production growth in emerging shale areas can be difficult to handle. This article reviews which gas processing technologies are appropriate for the variety of US shale gas qualities being produced and planned to be produced and reviews regional gas processing capacities to handle current and future production of shale gas.

On an industrial scale process, a comprehensive engineering design and optimization study was conducted for CO2 capture, dehydration, and compression facilities based on flue gases from natural gas and coal fired power plants. The HTC designer solvent was utilized in this chemical absorption process to achieve CO2 recovery targets from 80 to 90%. The captured and conditioned CO2, with more than 99 mol% purity, was compressed to 150 barg and sent out at the boundary limit for enhanced oil recovery applications. The main design and engineering factors affecting the CO2 capture, dehydration, and compression processes have been highlighted in this paper. The study provides a feasible engineering design and acceptable production cost taking into consideration all the technical, economic, and plant location factors. The study shows that it is advantageous to use the HTC designer solvent over the conventional monoethanolamine (MEA) solvent mainly due to its lower steam consumption, solvent losses, circulation rate, and cooling water requirements. Based on the objective function, the assumed industrial constraints, and the plant location factor, the production cost is estimated to be about 49 US$/ton CO2 for the 90% CO2 recovery of 4.0 mol% CO2 content in the flue gas of a natural gas combined cycle power plant. However, a substantial reduction in the production cost was reported for higher CO2 contents in the flue gas of a coal power plant. For a similar CO2 production capacity of 3307 ton per day from a 12 mol% CO2 content in flue gas of a coal fired power plant, the production cost is about US$ 30/ton CO2. This substantial reduction in the production cost is mainly because of the higher CO2 contents in the flue gas.

Physical solvents such as DEPG (Selexol™ or Coastal AGR®), NMP or N-Methyl-2- Pyrrolidone (Purisol®), Methanol (Rectisol®), and Propylene Carbonate (Fluor Solvent™) are becoming increasingly popular as gas treating solvents, especially for coal gasification applications. Physical solvents tend to be favored over chemical solvents when the concentration of acid gases or other impurities is very high. In addition, physical solvents can usually be stripped of impurities by reducing the pressure without the addition of heat. This paper compares the acid gas removal ability, required equipment, and power requirements for the four physical solvents DEPG, Methanol, NMP, and Propylene Carbonate.

In amine sweetening units, the heat of absorption and VOC and BTEX solubility have been found to vary significantly with acid gas loading as well as with temperature, amine type, and amine concentration. The heat of absorption declines by up to 20% while VOC and BTEX solubility can drop by as much as 40 to 50% with loadings up to 0.5 mol/mol for MDEA solutions. VOC and BTEX solubility are also highly dependent on temperature and amine concentration. As a result, amine sweetening units should be operated at the lowest circulation rate possible as limited by corrosion and treating requirements. For example, over circulation of 100 gpm in amine sweetening units can cost about $250,000/yr in additional reboiler fuel, can greatly increase pick up of VOC and BTEX, and lead to problems with emissions or in downstream sulfur recovery units.

The occurrence of liquid hydrocarbons in natural gas transmission lines has increased in recent years as a result of the shrinking price spread between natural gas and natural gas liquids (NGL's). Consequently, there is increasing interest among many pipeline companies in monitoring hydrocarbon dew point (HCDP) and liquids in the transmission lines to ensure the safety and reliability of the system. This paper examines the methods available for determining the HCDP of natural gases and their implementation in transmission systems. A case study is presented on Questar Pipeline Company's management and control of HCDP issues in their interstate gas transmission system in Utah, Wyoming and Colorado.

Michael W. Hlavinka, Ph.D., P.E. Vicente N. Hernandez, Ph.D. Bryan Research & Engineering, LLC Bryan, TX , U.S.A. Dan McCartney Black & Veatch Energy Overland Park, Kansas, U.S.A. This paper focuses on the modeling of solid phase behavior in systems that are frequently encountered in natural gas processing. The ability to perform accurate calculation of freezing or solids formation conditions in processes from dry ice, hydrates, and water ice is quite important. Although the primary focus in this work is on dry ice formation from carbon dioxide, analogies with hydrate formation are presented. A description of the phase equilibria at different conditions of temperature and pressure is included. The paper compares the predicted results from simulation with selected experimental data sets, and illustrates that accurate results are obtained over a wide variety of conditions. However, due to the complicated phase behavior of these systems, improper interpretation of results, or incorrect use of the tools within the simulator is possible due to the multiplicity of incipient formation points. One fact that is not well known is that lowering the temperature may cause a solid that has formed to melt under certain conditions of pressure and composition. While recent work has been done to mitigate the incorrect application of these tools, knowledge of some of the different types of phase behavior is generally desirable to understand and exploit the results. Phase diagrams are presented to aid in understanding the solid formation behavior.

Process simulators have been used for years to design and model actual operation of all types of different plant processes. The majority of process simulators provide a "steady-state" picture of plant operations and do not account for changes in inlet or ambient conditions. Steady state simulators are very useful when first designing a plant under a certain set of conditions, or when developing a baseline for plant operation. These simulators are also much more affordable than the dynamic simulators that are available in today's market. Unfortunately, plant operating conditions very seldom match design conditions and it is difficult for the Operator to discern what effect the changing conditions have on his process without performing numerous simulations using trial and error and manual manipulation. Even then, these results are often times suspect. Crosstex Energy Services, L.P. and Bryan Research and Engineering, LLC undertook a project to model one of the Crosstex gas processing facilities using the ProMax simulation software. Using the program's capabilities to rate the performance of various plant equipment, as it executes the simulation, and by utilizing available parametric study features that allow numerous runs to be made consecutively, without interruption, the ProMax simulator was able to provide a series of "snapshots" that provided a realistic and accurate prediction of how the plant will respond to changes in conditions. While this is still a prediction of steady state operation, the simulator has approached the dynamic threshold and only lacks the time derivative to cross over into that next dimension. This paper will show the steps that were taken to reach this point, the benefits it provided and how it might be used at other plant locations.

Most engineers have little familiarity with the software technologies that provide the framework for the variety of applications they employ, from word processors to process simulators. While adequate for casual use of an application, a more thorough understanding of these technologies is required in order to extend an application and provide custom behavior. Usually the effort required to perform small customizations is not significant provided the framework is understood. This paper introduces Object-Oriented Programming (OOP), OLE Automation, and Extensible Markup Language (XML), three common technologies used in programs. A conceptual discussion of OOP is presented along with examples where the paradigm may be encountered. Automation is introduced with illustrations of how this feature can extend an application. Finally, XML is summarized along with a discussion of some of the tools and supporting technologies used with XML. The aim of this paper is to give a basic understanding of how and when these technologies can be exploited based on specific applications and tasks.

Due to the increase in natural gas prices in the past few years, the benefits of optimizing natural gas gathering and processing systems have become substantially greater. These benefits can be observed from an analysis of the operating conditions, updating gas contracts, and adding gas to existing systems when excellent opportunities exist. A new technique has been developed to accurately model gas processing systems to incorporate an economic simulation with the process simulation. This new technique utilizes an Excel interface with process simulation software to include economic factors with the simulation results. As a result, an extended analysis of the operating conditions of the facility as well as the economic conditions can be simultaneously combined to provide a complete model of the system. This methodology can be extended to include a parametric study of the available process and economic variables. Excel solvers may also be used to generate the economic optimum set operating conditions.

W.G. "Trey" Brown Bryan Research and Engineering, LLC Bryan, Texas, U.S.A. Leonard Ochs Williams Tulsa, Oklahoma, U.S.A. J.W. Varner Quicksilver Resources, Inc. Ft. Worth, Texas, U.S.A. The use of process simulators to model plant operations can provide a plant hundreds of thousands of dollars each year in increased production and lower energy costs. This paper looks at several example plants where process simulators were utilized to optimize their operation and measurable results were obtained. Each of these plants were able to improve their bottom line profit because a process simulator was available and plant personnel were dedicated to using it to improve plant performance and efficiency. In today's economic roller coaster, where product margins can be positive one day and negative the next, a plant must be designed and operated with the utmost operating flexibility, while maintaining high energy efficiency. The process simulator allows both the designer and the operator to maximize this flexibility and determine the best way to operate the plant at both ends of the operating spectrum. Today, a plant that does not use a simulator to monitor its operation is simply throwing money away.

Hydrate inhibition with methanol continues to play a critical role in many operations. Opportunities exist at many facilities for optimizing the amount of methanol required based on the operating conditions. To properly predict these requirements, the distribution of the methanol between the gas and liquid phases is of key importance. Significant contributions by the GPA research program both in past years and current or future research projects make it possible to better predict methanol requirements for hydrate inhibition from commercial simulators. However, a proper understanding of experimental methods and actual sample and overall compositions is very important to an accurate interpretation of the results.

HC and BTEX absorption into amine solutions has received increased attention over the last decade due to emissions to the atmosphere or to problems in downstream equipment. The collection of VLE and VLLE data by GPA and others have facilitated the development of a model for the absorption and removal processes. The amount of HC and BTEX emitted or passed to downstream equipment may be controlled by reducing the absorption or by removal from the rich amine.

Hydrate inhibition with methanol continues to play a critical role in many operations. Numerous opportunities exist for optimizing methanol usage based on the operating conditions, seasonal variations in temperature, and accurate prediction of the hydrate formation temperature. To properly predict the requirements, the distribution of methanol between the gas and liquid phases is of key importance. These opportunities for optimization have been made possible primarily through research data from the GPA.

This paper will investigate how computer aided simulation tools may be used to evaluate the existing acid gas handling systems as well as potential modifications in these units. In particular, the benefits of changing amines, debottlenecking sulfur plants, oxygen enrichment, tail gas treatment options and general rules for optimizing these units will be reviewed. As a rule, it is always wise to determine the operational efficiency for each unit before any major modifications are initiated. This will hopefully prevent a new design from failing due to previously undetected internal or other problems.

Amine solutions absorb some amount of hydrocarbons and BTEX. These dissolved hydrocarbons that are obtained by contacting with the feed gas are ultimately released in the overhead of the regenerator. This overhead either vents to the atmosphere or feeds a sulfur recovery unit. Hydrocarbon content for regenerator vents discharging to the atmosphere must comply with recent stringent regulations. For acid gas feeds to a Claus unit, excessive hydrocarbons may result in catalyst fouling, sub-quality sulfur product, or more sophisticated burner design. To better understand and quantify hydrocarbon and BTEX solubility in aqueous amines, the Gas Processors Association commissioned research Project 971. Preliminary results from this project have been used to improve models for hydrocarbon and BTEX solubility predictions. Model predictions are compared with operating facilities and guidelines for minimizing hydrocarbon absorption in amine facilities are presented.

Environmental regulations controlling the amount of H2S emissions require the Aquila Navasota Gas Plant to treat the acid gas from the main amine-treating unit to meet standard specifications. Originally, a batch process was installed to remove a portion of the H2S, bypassing the remaining gas, to meet the specifications. Operating cost of this batch process increased as the H2S content increased and became excessive. This required Aquila to investigate alternative processes. Process evaluations were requested from several sources and a large variance in unit designs was found. Due to the unique nature of the feed gas, 96+% CO2 and < 1000 ppm H2S at 10 psig, conventional design technology for amines required a higher circulation rate and excessive CO2 absorption. Since the recovered H2S would be sent to a flare, fuel consumption would be higher with the excess CO2. One design, provided by Huntsman Corporation, was found to offer the lowest capital investment along with lower operating cost. This design utilized specific design parameters in the absorber that allowed the circulation rate to be less than one-third of the other designs. Unit operating parameters will be reviewed and have been within original estimates. Design also allows for a wide range of operating conditions without much change in treated specifications. Design and operating characteristics will be reviewed.

Methanol is probably one of the most versatile solvents in the natural gas processing industry. Historically, methanol was the first commercial organic physical solvent and has been used for hydrate inhibition, dehydration, gas sweetening and liquids recovery. Most of these applications involve low temperature where methanol's physical properties are advantageous compared with other solvents which exhibit high viscosity problems or even solids formation. Operation at low temperatures tends to suppress methanol's most significant disadvantage, high solvent loss. Methanol has been extensively used as a hydrate inhibitor for conditions where the Hammerschmidt equation is applicable. Outside this range, predicting methanol's behavior is more complicated than the empirical correlations that are provided in industrial standard data books. In fact, the thermodynamic properties and phase equilibrium of mixtures of methanol, water and hydrocarbons are notoriously difficult to predict. Methanol shows both polar and non-polar characteristics. Consequently, these characteristics give methanol the unique ability to be used in an extensive range of applications. This paper will review some of these diverse applications: hydrate inhibition, gas dehydration, sweetening and liquids recovery.

A new method to determine the optimum performance of natural gas processing plants has been developed. This methodology reduces the overall plant material balance equations into a linear form using the volatility of components and product specifications. Simulator response modeling relates key process variables to plant performance satisfying the remaining unknown information from the material balance equations. Rigorous economics are subsequently applied to the process model. This technique adequately combines contractual terms, product prices, and process information to calculate the optimum set of operating conditions for the plant offline. It is also a valuable tool to analyze the economic impact of processing additional streams and investigating new potential contract scenarios.

This paper compares the solubility of hydrocarbons in several physical solvents such as ethylene glycol, diethylene glycol, triethylene glycol, methanol, and dimethyl ethers of polyethylene glycol (DEPG, a solvent marketed by Union Carbide, UOP, and Coastal). Most of these solvents are designed to extract unwanted components such as water and acid gases. However, these solvents also have a tendency to remove the hydrocarbon product. Quantifying this amount of absorption is critical in order to minimize hydrocarbon losses or to optimize hydrocarbon recovery depending on the objective of the process. The influence of several parameters on hydrocarbon solubility including temperature, pressure and solvent water content is examined. Suggested operating parameters to achieve hydrocarbon absorption objectives are included. Hydrocarbon solubility is a major factor when considering the use of a physical solvent.

There are many possible process variations for sweetening sour hydrocarbons with amines. Those to which we have given attention include the use of precontactors (static or jet eductor mixers), multiple absorber inlet nozzles, split flow units and pressure swing regeneration. Each of these variations is best suited to a certain set of operating conditions. Not all processes are appropriate for use with certain feed compositions or product requirements. This paper will discuss the application of the various flow scheme alternatives to a variety of different process conditions.

Over the years, the Gas Processors Association (GPA) has appropriated funding toward research that has served the Gas Processing Industry in many ways. Perhaps the most significant manner in which the benefits of this research have been realized is through more accurate measurements of phase equilibria, enthalpy, density, and other physical properties leading to more efficient engineering analysis and design. In particular, the accuracy of process simulators has been dramatically improved since these basic properties are involved in virtually every calculation. This article will review many of the projects undertaken by GPA. The article will provide examples where accurate predictions were not possible for engineering calculations due to lack of data, but today are performed routinely due to data collected under GPA research. Finally, the article will suggest some areas of possible research where current data are limited.

Gas treating process variables such as solvent type and concentration, pressure, and circulation can be manipulated to produce specification quality hydrocarbon products. Interest has increased recently in exploring the effects of inlet gas and solvent temperatures as an aid in meeting these specifications. In general, lower temperatures tend to promote absorption of lower molecular weight components based on vapor-liquid equilibrium. Physical solvents exploit this principle by absorbing acid gases and water at lower temperatures. If the absorption process is reactive and allowed to reach equilibrium, lower temperatures still favor the absorption of low molecular weight components. However, if the reactive absorption is kinetically limited as is the case with CO2 and certain amines, it is impossible to determine how temperature affects the absorption in the absence of additional information. This ambiguity results from the competing phenomena and opposite effect temperature has on reaction rates and solubility. For absorption of H2S and CO2 in alkanolamines or mixtures of amines with physical solvents, H2S absorption reaches equilibrium conditions while CO2 absorption is kinetically limited in some situations. The performance of various amines and physical solvents are compared based on solvent and feed gas temperatures. Understanding the competing phenomena of equilibrium and kinetics may yield situations where this effect can be exploited for more profitable operation.

This paper will discuss and compare the methods used to suppress hydrate formation in natural gas streams. Included in the comparison will be regenerated systems using ethylene glycol and non-regenerated systems using methanol. A comparison will be made between the quantities of methanol and ethylene glycol required to achieve a given suppression. A discussion of BTEX emissions resulting from the ethylene glycol regenerator along with the effect of process variables on these emissions is also given.

Due to the addition of new wells, the feed to Ferguson Burleson County Gas Gathering System (FB) Anderson gas treating plant was scheduled to increase from 180 MMSCFD to a design capacity of 210 MMSCFD. The feed gas contained both CO2 (6.0 mol %) and H2S (25 ppm) at high pressure (980 psig). A feasibility study determined that a cost effective method to handle the additional gas volume was to switch from a single amine to an amine mixture and to add static mixers to treat a bypass stream for H2S. The primary amine contactors would perform bulk removal of the acid gases from the main stream. Although increased treating capacity was the ultimate goal, a secondary concern was that corrosion be kept to within acceptable limits. To be certain this concern was adequately addressed, all of the heat exchangers within the system were rated and heat fluxes were investigated for possible problem areas. Several different amine mixtures were also evaluated with an eye toward potential corrosion limitations. This paper discusses the modifications made to the system and the results of subsequent plant trials to determine the overall capacity increase.

This paper describes an application of advanced multivariable control on a natural gas plant and compares its performance to the previous conventional feed-back control. This control algorithm utilizes simple models from existing plant data and/or plant tests to hold the process at the desired operating point in the presence of disturbances and changes in operating conditions. The control software is able to accomplish this due to effective handling of process variable interaction, constraint avoidance, and feed-forward of measured disturbances. The economic benefit of improved control lies in operating closer to the process constraints while avoiding significant violations. The South Texas facility where this controller was implemented experienced reduced variability in process conditions which increased liquids recovery because the plant was able to operate much closer to the customer specified impurity constraint. An additional benefit of this implementation of multivariable control is the ability to set performance criteria beyond simple setpoints, including process variable constraints, relative variable merit, and optimizing use of manipulated variables. The paper also details the control scheme applied to the complex turboexpander process and some of the safety features included to improve reliability.

The amount of BTEX components emitted from gas processing facilities has become a significant environmental concern. Recently, amine sweetening units have received the same environmental scrutiny as glycol units with regard to BTEX emissions. This paper compares the BTEX emissions from amine sweetening and glycol dehydration facilities as well as the methods available to minimize BTEX pickup in these systems. Reducing solvent circulation rates in both the amine and glycol units and minimizing the lean amine temperature were found to be the most effective ways of limiting overall BTEX emissions. Changing solvent type can also reduce emissions, but the effect on treated gas quality must be considered as well. In the cases investigated approximately 25% of the overall BTEX emissions came from the amine units, while the remaining 75% came from the glycol system 1998 Laurance Reid Gas Conditioning Conference Proceedings. Norman, Oklahoma: University of Oklahoma.

Engineers are continually being asked to improve processes and increase efficiency. These requests may arise as a result of the need to increase process throughput, increase profitability, or accommodate capital limitations. Processes which use heat transfer equipment must frequently be improved for these reasons. This paper provides some methods for increasing shell-and-tube exchanger performance. The methods consider whether the exchanger is performing correctly to begin with, excess pressure drop capacity in existing exchangers, the re-evaluation of fouling factors and their effect on exchanger calculations, and the use of augmented surfaces and enhanced heat transfer. Three examples are provided to show how commercial process simulation programs and shell-and-tube exchanger rating programs may be used to evaluate these exchanger performance issues. The last example shows how novel heat transfer enhancement can be evaluated using basic shell-and-tube exchanger rating calculations along with vendor supplied enhancement factors.

BTEX emissions from glycol dehydration units have become a major concern and some form of control is necessary in many cases. One method of reducing BTEX emissions that is often overlooked is in the selection of the proper dehydrating agent. BTEX compounds are less soluble in diethylene glycol (DEG) than triethylene glycol (TEG) and considerably less soluble in ethylene glycol (EG). If the use of DEG or EG achieves the required gas dew point in cases where BTEX emissions are a concern, a significant savings in both operating costs and the cost of treating still vent gases may be achieved. This paper compares plant operations using TEG, DEG, and EG from the viewpoint of BTEX emissions, circulation rates, utilities, and dehydration capabilities.

Recovery of elemental sulphur from acid gas was first performed via the Claus process over 100 years ago. This article examines some Claus modifications which can alleviate operational difficulties and improve overall sulphur recovery.

Scott Fulton, Costal Corporation, USA, and Jay Collie, Bryan Research and Engineering, LLC, USA, discuss the use of process simulators to analyse the performance of heat transfer equipment, focusing particularly on brazed aluminium heat exchangers

The removal of trace components from a gas by absorption using a chemical solvent is of importance to the gas processing industry. There is a growing interest in reaching lower outlet concentrations for reasons of health and safety; however, this requires very high energy use for solvent regeneration. Instead, solid-adsorption-based processes are often used as a secondary treatment step. We have developed new processes for liquid absorption that exploit better understanding of the thermodynamics of chemisorption processes in mixed solvent systems. The new processes use any conventional solvent and incorporate recycles between the absorber and stripper, by means of which the thermodynamic and process conditions for stripping are optimized to reduce the process heat requirement at high separation efficiency. Using these new processes it is possible to reach sub-ppm concentrations of acid gas with considerable savings in energy costs and without requiring use of solid sorbents. The new technology is based on conventional vapor-liquid contacting equipment and is suitable for retrofit to existing plant.

The amine process will absorb heavy hydrocarbons and aromatics from gas streams in addition to the acid components. Whether the acid gas is to be vented or fed to a sulfur plant, it is highly desirable to remove these compounds from the acid gas. A new, economical process has been developed to greatly reduce the aromatics and heavy hydrocarbons in the amine plant acid gas stream. In the test facility, the new BTEX-T. rex process decreased the level of aromatics in the acid gas stream by more than three quarters. The process utilizes the plant fuel gas as a stripping agent and the aromatics and heavy hydrocarbons which are removed are incinerated in the amine plant reboiler heater. Plant data collected before and after implementing the BTEX-T. rex process compare favorably with the results estimated using a recent version of TSWEET regarding BTEX concentration results.

Following these guidelines will ensure a well-designed and efficient plant.

Increasingly stringent sulphur emissions regulations often require renovation of older sulphur recovery units (SRUs) to improve overall recovery. Optimization or modification of an existing Claus SRU or the design of a new unit can be simplified by use of a process simulator. In this paper, Karl W. Mattsson-Bozé and Lili G. Lyddon of Bryan Research & Engineering present examples to show how TSWEET® can be used to model a Claus SRU and then to simulate modifications to aid in evaluating the best design.

Brazed aluminum heat exchangers have superior heat transfer capabilities and can be cost effective for non-corrosive gases and liquids as compared with traditional shell-and-tube exchangers. Even so, brazed aluminum exchangers are often not considered because of complicated design equations and complex stacking arrangements. The simpler yet less efficient shell-and-tube exchangers or networks of shell-and-tubes are employed instead. Recently, the design equations for multistream brazed aluminum heat exchangers for both single and multiphase flow have been added to the Heat Exchanger Rating package of the process simulator PROSIM® . This paper presents guidelines for designing a brazed exchanger, and the brazed exchanger is compared with traditional shell-and-tube exchangers and networks of exchangers in several examples.

Mixing amines can be the best method for increasing capacity or improving efficiency in an amine sweetening unit. In many cases, it may be possible simply to add a second amine to the existing solution "on the fly", or as the unit is running.

The dramatic increase in the use of selective amines for gas sweetening has resulted from the inherent economic benefits including smaller equipment sizes, lower circulation rates, and higher overall amine concentration. Selective amines absorb H2S in the presence of CO2, either from thermodynamic solubility or kinetic effects. Mixtures containing selective amines can be formulated to allow a certain amount of CO2 to remain in the processed gas. Units designed with selective amines often have little margin for error with respect to plant capacity. Unfortunately, increases in the acid gas concentration or increases in throughput exceeding design can result in sweet gas which does not meet the CO2 specification. Since adding additional equipment can be very expensive, variables such as increasing the amine concentration, using mixtures of amines, and varying the lean amine temperature affect amine sweetening were studied. These variables require little or no additional capital expenditure relative to other alternatives such as adding reboiler area or pumping capacity.

A wealth of information covering almost every conceivable topic is available by way of the Internet. A significant amount of this information is useful to the engineer. Also, the Internet makes it possible to connect computers and communicate information in a variety of ways. This article discusses the basic aspects of the Internet as well as the ways in which an engineer might use of it.

New restrictions on vaporization loss os petroleum products give added emphasis to the measurement of vapor pressure for petroleum fractions and their blends. The common method for measuring vapor pressure is the Reid vapor pressure (Rvp) test. Now an algorithm is available to calculate Rvp without performing the actual test. The algorithm, based on air-and-water free model, uses the Gas Processors Association Soave-Redlich-Kwong equation of state and assumes liquid and gas volumes are additive. Since the calculations are iterative, they are incorporated into a general purpose process simulator to compare predicted values with experimental data. Good agreement is found between predicted and experimental values. Furthermore, the algorithm is fast and can be used to predict Rvp of any hydrocarbon mixture of known composition.

This paper is an update from the original in: Energy Progress September 1984: 146-150. The selection of an amine for gas sweetening is complex and must be based on several process considerations. These factors are analyzed based on experimental data and a process simulation program for gas sweetening called TSWEET.

Emphasis on environment concerns has pushed sulfur emissions to the fore-front. Present three stage Claus plants cannot reach the sulfur recovery requirement for small gas processing plants, therefore some form of special tail gas cleanup unit is required. Several processes yield higher recoveries than the three stage Claus unit but this paper is directed to an integrated system with a primary amine unit, a Claus unit, and a tail gas clean up unit. The overall sulfur recovery is in excess of 99.8%.

The effects of ammonia in the feed to amine sweetening units has been investigated using a process simulation program called TSWEET®. In the cases studied, MEA and MDEA were used to treat gases contaminated with up to 0.3% ammonia. The MEA units studied were 1100 psi gas contactors sweetening 0.25 to 4% H2S and 0.25 to 2.5% CO2. The MDEA units were 300 and 20 psi units treating high CO2 streams in a selective manner. Small amounts of ammonia can cause serious problems in some amine sweetening units. These problems are usually traceable to a complex of ammonia with CO2 in the stripper. When large amounts of CO2 are present, this complex may cause a build up of CO2 and ammonia in the circulating amine. In MEA, ammonia tends to push CO2 into the reboiler, increasing the CO2 residuals and ammonia in the lean amine. In MDEA, the ammonia appears to help drive CO2 overhead, decreasing CO2 and increasing the H2S in the stripper bottoms.

Over the past several years, concerns about hydrocarbon emissions from the regenerator vent in glycol dehydrators has become a significant issue. This paper illustrates the prediction capabilities of PROSIM® for analyzing these concerns. First, the paper illustrates that predictions made by PROSIM compare favorably to data from the API Glycol Reboiler Emissions Work Group. Next, PROSIM shows that while a significant amount of non-aromatic VOC emissions are released in the flash separator, a small fraction of BTEX emissions are evolved at normal conditions. PROSIM indicates that over-circulation does not enhance dew point depression, but will cause a nearly linear increase in the amount of BTEX compounds emitted from the unit. Next, various contactor pressures are analyzed which show that higher emissions result from lower pressure units due to the increased amount of water that must be absorbed. Finally, a comparison between DEG and TEG facilities with similar circulation rates indicates that approximately 30-40% more BTEX emissions occur when using TEG than DEG.

In designing dehydration units for natural gas, several critical parameters exist which can be varied to achieve a specified dew point depression. This paper studies the effects of varying the glycol flow rate, number of stages in the contactor, reboiler temperature, and stripping gas rate on water content in glycol dehydration units. The effect of high carbon dioxide composition in the feed is also presented. Finally, the emissions of aromatic (BTEX) and other VOC's from the regenerator and flash will be considered.

The use of amine mixtures employing methyldiethanolamine (MDEA), monoethanolamine (MEA), and diethanolamine (DEA) have been investigated for a variety of cases using a process simulation program called TSWEET . The results show that, at high pressures, amine mixtures have little or no advantage in the cases studied. As the pressure is lowered, it becomes more difficult for MDEA to meet residual gas requirements and mixtures can usually improve plant performance.

Integrated gas sweetening, sulfur and tail gas cleanup units (TGCU) were analyzed by a process simulation program, called TSWEET, to determine the sensitivity of the operating conditions and parameters on the performance of the system. The parameters investigated included the H2S/CO2 ratio in the acid gas from the main absorber, the hydrocarbon content of the acid gas, the reaction model for H2 and CO in the furnace, the formation and reaction of COS as well as CS2 and the CO2 slippage in the TGCU absorber. For the assortment of cases considered, the results showed that while some parts of the system were not overly sensitive to many of the operating conditions others were quite sensitive. Due to the complexity of the integrated system, a parameteric analysis is necessary to fully optimize the system.

The use of MDEA and mixtures of amines for bulk CO2 removal was explored using three case studies. A process simulation program called TSWEET was used to study the effect of the amine used and the major operating parameters on the performance of MDEA solutions for bulk CO2 removal. The results showed that MDEA can be used quite advantageously for bulk CO2 removal and that the performance is often very sensitive to one or more of the operating parameters: liquid residence time on the trays, circulation rate and lean amine temperature. A good parametric analysis of the operating parameters should be performed in every case.

Seven unweathered heavy residual oils, analyzed and compared for source identification purposes, demonstrate that the comparison of heavy residual oils must be performed with great care using a variety of analytical techniques and comparison methods. Furthermore, these methods are best applied to known common-source pairs and to known non-common-source pairs in addition to the unknown pairs. Physical and chemical tests showed that, for the most part, these properties for the seven oils were within the error range of the test. Visual comparison of the chromatograms also showed that they were very similar. Normalized normal paraffin and isoprenoid peak height profiles, when subjected to measurement-error and statistical comparisons, provided quantitative evaluations of the relative likelihood that the members of the various oil pairs were from a common source.

Since complex brazed aluminum plate exchangers can include as many as 8-10 process streams within a single exchanger, the process design calculations become quite involved and must include incremental duty versus temperature calculations to check for temperature pinch points. The capability to perform the process design for complex plate exchangers has recently been added to a process simulation program called PROSIM. Three case studies involving the simulation and optimization of cryogenic operations for liquids recovery from gases using complex plate exchangers are presented. Due to their low cost and superior heat transfer capabilities, complex plate exchangers can be very useful in reducing costs and optimizing cryogenic operations.

Amine solutions are often used to treat LPG streams that contain acid gases. In this work, the selection of an amine and the method of contacting the amine with a 50gpm [189 lpm] LPG stream containing 7.7 mol% as CO2 are evaluated. A packed contactor is compared to a static mixer and MEA, DEA, and MDEA are compared as potential solvents. A static mixer using 70 gpm [265 lpm] of 25 wt.% DEA is chosen for the final design. The operating data reveal 0.10 mol% CO2 in the sweet LPG compared to the design value of 0.16 mol%.

Operating data were collected from the Signalta gas sweetening plant. The plant has had an interesting variety of feed gas and operating conditions. The design and operation of the facility for CO2 slippage are discussed.

In today's competitive economy, the engineer must become as productive as possible. One means of increasing productivity is to use process simulation packages and other engineering computer aids to their maximum utility. In addition to increasing the engineer's productivity, process simulation packages may be used to analyze operating problems in existing plants and to design new facilities. In general, the virtues of process simulation have become well recognized in the industry and most process engineers have some type of simulation capability available to them. In the last few years, major emphasis has been placed on increasing the engineer''s productivity with process simulation packages. This includes the "up front" time to learn to use the simulator as well as the time to produce a completed analysis once the engineer has become familiar with the simulator. This need for increased engineering productivity has generated a new type of tool called interactive process simulation.

Currently, the most common method to analyze for acid gases in amine solutions is by wet chemistry titration which is both tedious and time consuming. A simple gas chromatographic method now exists which is accurate and performs one analysis within eight minutes.

Canada's first plant conversion from DEA to MDEA is a success. Dome's North Caroline amine plant performs very smoothly after being debottlenecked to, at least, original design capacity. Performance data taken for the absorber at several amine flow rates compare with safe accuracy to values calculated by the TSWEET program that was used as the basis for conversion.

Precipitation of solids is one of the major problems associated with the shipping and handling of heavy residual oils especially No. 6 heating oil. ASTM specifications which currently include viscosity, flash point and pouring point are not adequate to predict the handling problems. The residual oils are becoming more complex in composition due to modern refinery techniques for cracking the heavier residues into distillable fractions. In this study, several heating oil samples, including a sample which partially solidified during transport, were analyzed using various techniques including separation by gel permeation chromatography (GPC), vacuum distillation, separation of petroleum asphaltenes by ASTM method, elemental analysis and proton and 13C NMR spectroscopy. The distillable species in the fraction separated by GPC were characterized by high resolution gas chromatography-mass spectroscopy (GC-MS). The study showed that the GPC can be used as a reliable technique for the analysis of heavy residual oils. The GPC separation of No. 6 heating oil gave three fractions enriched with chemically distinct asphaltenes. The second fraction was mostly straight chain paraffins. The third fraction was composed of low molecular weight aromatics. Although occasional verification of GPC data by GC-MS and by NMR spectroscopy is desirable, the GPC alone is an efficient analytical tool for evaluating the composition as well as predicting the handling problems associated with shipping and storage of various residual oils.

As more LPG's (liquefied petroleum gas) are being produced, the demand for liquid hydrocarbon sweetening facilities has increased. The most common contaminants in LPG's are CO2, H2S, mercaptans, COS, CS2, and elemental sulfur. Each of these contaminants can cause problems in the finished products.

A severe case of incompatibility occurred when three residual fuel oils were shipped as a blend. The oils were blended as they were being loaded. During transport, a tar-like precipitant formed, settled to the bottom and partially solidified. These fuel oils were analyzed in an attempt to predict future potential incompatibility problems and to investigate the known case of incompatibility. Hydrocarbon Processing September 1983: 101-103.

A version of this paper ("How to Reduce Costs in Amine Sweetening Units")also appeared in: Chemical Engineering Progress March 1983: 63-67. The design capability for gas-sweetening units has improved greatly. The selection of an efficient alternative flowsheet minimizes capital and operating costs.

The selective removal of H2S from gas streams containing CO2 has become of widespread interest as a means to reduce equipment sizes and operating cost. A selective absorption design capability has been added to the amine sweetening process simulation program, TSWEET. The program results agreed closely with selective absorption data using MEA at contact times of about 0.4 seconds. The program calculations also agreed with a 40% CO2 rejection measured in a DEA absorber operating at 11 psig and 2 seconds residence time per tray. A 6-ft diameter absorber using 15 wt% MDEA was also used for comparison. The calculated H2S in the sweet gas was well within the scatter of the data while the calculated CO2 rejection was about 10% high. The process simulation program accurately represents the selective absorption process including the influence of all process variables.

Large volumes of natural gas are produced throughout this country and Canada for the purpose of heating homes, producing electricity and generating heat for a wide variety of industries. As it comes from the ground, much of the gas produced contains quantities of acid gases, notably H2S and CO2. The carbon dioxide is of little consequence for the most part, but H2S is quite toxic and virtually all of this gas must be removed before the gas can be sent to commerical pipeline.

Vapor-liquid equilibrium is predicted by using the Soave modification of the Redlich-Kwong equation of state (EOS). The concept of equal fugacities is used to calculate the equilibrium constant, Ki=yi/zi, then, it is shown how the Murphree tray efficiency can be applied on the liquid or the vapor phases to modify that constant. The derivatives needed are calculated numerically, and it is shown that for absorbers and distillation columns, Murphree tray efficiency applied this way can be used to simulate the actual number of stages. Murphree tray efficiency values can be specified for one, several or all of the components on any stages of a column. A dehydration example is shown, the dew point depression values of a mixture of water-gas, using a triethylene glycol solution for dehydration purposes, are calculated by incorporating the method into a process simulator program called PROSIM® and compared with the values reported in the literature.

Technical paper from the BR&E archive.

Technical paper from the BR&E archive.

Technical paper from the BR&E archive.