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.

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.

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.

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.

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.

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, Inc. 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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.