John Y. Mak

Natural Gas Fundamentals

Natural gas is the most energy efficient fossil fuel—it offers important energy saving benefits when it is used instead of oil or coal. Although the primary use of natural gas is as a fuel, it is also a source of hydrocarbons for petrochemical feedstock and a major source of elemental sulfur, an important industrial chemical. Its popularity as an energy source is expected to grow substantially in the future because natural gas can help achieve two important energy goals for the twenty-first century—providing the sustainable energy supplies and services needed for social and economic development and reducing adverse impacts on global climate and the environment in general. This chapter gives the reader an introduction to natural gas by describing the origin and composition of natural gas, gas sources, phase behavior and properties, and transportation methods.

Natural Gas Compression

“Compression” is used in all aspects of the natural gas industry, including gas lift, reinjection of gas for pressure maintenance, gas gathering, gas processing operations (gas loading and discharge), transmission and distribution systems, and boil-off systems (in gas storage and tankers for vapor control and to avoid releasing gas to the atmosphere). In recent years, there has been a trend toward increasing pipeline-operating pressures. The benefits of operating at higher pressures include the ability to transmit larger volumes of gas (referred at base conditions) through a given size of pipeline, lower transmission losses due to friction, and the capability to transmit gas over long distances without requiring or even reducing additional compressor stations. In gas transmission, two basic types of compressors are used: reciprocating and centrifugal compressors. Reciprocating compressors are usually driven by either electric motors or gas engines, whereas centrifugal compressors use gas turbines or electric motors as drivers. Both gas engines and gas turbines can use pipeline gas as a fuel, but electric motors have to rely on the availability of electric power. Due to the number of variables involved, the task of choosing the optimum driver can be quite involved, and a comparison between the different types of drivers should be done before a final selection is made. An economic feasibility study is of fundamental importance to determine the best selection for the economic life of a project. Furthermore, it must be decided whether the compression task should be divided into multiple compressor trains, operating in series or in parallel. This chapter presents a brief overview of the two major types of compressors, a procedure for calculation of the required compression power, as well as additional and useful considerations for the design of compressor stations. All performance calculations should be based on compressor suction and discharge flange conditions. For reciprocating compressors, pressure losses at the cylinder valves as well as the pressure losses in pulsation dampeners have to be included in the calculation. Additional losses for process equipment such as suction scrubbers, intercoolers, and aftercoolers have to be accounted to define compressor design conditions.

Sulfur Recovery and Handling

Roughly 25% of the natural gas brought into production from new sources requires some degree of treatment to remove hydrogen sulfide (H 2 S) and recover elemental sulfur from acid gas streams containing H 2 S in high concentrations. In fact, due to the latest legislation plus environmental and safety considerations, venting or flaring H 2 S to the surroundings is now an unacceptable option, so conversion to elemental sulfur is necessary. Elemental sulfur is easy to store, handle, and transport in bulk. Ease of storage is an important advantage as it enables sulfur to be stockpiled economically in periods of reduced demand. Chemical conversion of H 2 S for disposal as solid waste (such as calcium sulfate) is technically feasible but uneconomical. Converting H 2 S to sulfuric acid is also a feasible option. However, sulfuric acid is both toxic and corrosive and, as a liquid, more expensive to store and transport than solid sulfur. Where environmental regulations permit and production of elemental sulfur is not economically attractive, injection wells provide a safe means for H 2 S disposal. This chapter discusses the properties of elemental sulfur and then describes the most common methods available for dealing with large quantities of H 2 S.

Basic Concepts of Natural Gas Processing

Natural gas coming from the well contains hydrocarbons, Carbon dioxide, Hydrogen sulfide, and water together with many other impurities. Raw natural gas after transmission through a network of gathering pipelines therefore must be processed in a safe manner and with minimal environmental effect before it can be moved into long-distance pipeline systems for use by consumers. While some of the needed processing can be accomplished at or near the wellhead (field processing), the complete processing of natural gas takes place at a processing plant, usually located in a natural-gas-producing region. The objective of a gas processing plant is to separate natural gas, associated hydrocarbons, acid gases, and water from a gas-producing well and condition these fluids for sale or disposal. The processing philosophy depends on the type of project being considered and the level of treating required, i.e., the difference between the feed gas and product specifications. This determines what components will need to be removed or recovered from the gas stream. This chapter describes the scope of natural gas processing and briefly reviews the function and purpose of each of the existing process units of the gas processing plants with greater details to follow in subsequent chapters.

Natural Gas Dehydration

Natural, associated, or tail gas usually contains water, in liquid and/or vapor form, at source and/or as a result of sweetening with an aqueous solution. Operating experience and thorough engineering have proved that it is necessary to reduce and control the water content of gas to ensure safe processing and transmission. Pipeline drips installed near wellheads and at strategic locations along gathering and trunk lines will eliminate most of the free water lifted from the wells in the gas stream. Multistage separators can also be deployed to ensure the reduction of free water that may be present. However, the removal of the water vapor that exists in solution in natural gas requires a more complex treatment. This treatment consists of “dehydrating” the natural gas, which is accomplished by lowering the dew point temperature of the gas at which water vapor will condense from the gas. There are several methods of dehydrating natural gas. The most common of these are liquid desiccant (glycol) dehydration, solid desiccant dehydration, and cooling the gas. Any of these methods may be used to dry gas to a specific water content. Usually, the combination of the water content specification, initial water content, process character, operational nature, and economic factors determine the dehydration method to be utilized. However, the choice of dehydration method is usually between glycol and solid desiccants. These are presented in depth in subsequent portions of this chapter.

Natural Gas Liquids Recovery

Most natural gas is processed to remove the heavier hydrocarbon liquids from the natural gas stream. These heavier hydrocarbon liquids, commonly referred to as natural gas liquids (NGLs), include ethane, propane, butanes, and natural gasoline (condensate). Recovery of NGL components in gas not only may be required for hydrocarbon dew point control in a natural gas stream (to avoid the unsafe formation of a liquid phase during transport), but also yields a source of revenue as NGLs normally have significantly greater value as separate marketable products than as part of the natural gas stream. Lighter NGL fractions, such as ethane, propane, and butanes, can be sold as fuel or feedstock to refineries and petrochemical plants, while the heavier portion can be used as gasoline-blending stock. The removal of natural gas liquids usually takes place in a relatively centralized processing plant, where the recovered NGLs are then treated to meet commercial specifications before moving into the NGL transportation infrastructure. This chapter presents the basic processes used to separate natural gas liquids from the gas, fractionating them into their various components, and briefly describes the processing required to produce marketable liquid products.

Natural Gas Treating

Natural gas, which consists of mainly methane and lighter hydrocarbons, also contains acid gases such as hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ). In addition to acid gases, natural gas may contain other sulfur contaminants such as mercaptans (R–SH), carbonyl sulfide (COS), and carbon disulfide (CS 2 ). The main challenge in todays natural gas treating units is to remove the high concentration of CO 2 from sour gas and the sulfur components to meet stringent emission standards. A number of methods are available for the removal of acid gases, which will be discussed in this chapter. The objective of this chapter is to review the basic concepts and discuss some of todays gas treating problems, but it is not intended to cover every aspect of gas treating.

Gas Processing Plant Automation

Automation has become an increasingly important aspect of gas processing. Automation provides the means for fully utilizing the mechanical capabilities of the equipment at all times and to run the process at its most efficient points in a stable and reliable fashion. A good automation platform can be leveraged to provide the right information at the right time to the right personnel to make the right decisions in a timely manner. This chapter discusses the elements of automating todays gas processing plants including considerations for instrumentation, controls, data collection, operator information, optimization, information management, etc. The advantages and disadvantages of various automation and control approaches are analyzed in this chapter. Also, strategies for identifying and quantifying the benefits of automation are discussed.

Gas Processing Plant Operations

A well-designed gas processing plant is not successful until it is operating safely and profitably. This requires a smooth start-up as well as a productive and safe environment for the operations. In order to sustain the operation, good maintenance practices are required. Troubleshooting is invariably required to detect and fix issues that occur when the performance of engineered equipment degrades. The objective of this chapter is to provide an introduction into commissioning and start-up, control room management, maintenance, and troubleshooting techniques applicable to gas processing plants.

Raw Gas Transmission

Natural gas is often found in places where there is no local market, such as in the many offshore fields around the world. For natural gas to be available to the market, it must be gathered, processed, and transported. Quite often, collected natural gas (raw gas) must be transported over a substantial distance in pipelines of different sizes, due to drive for reduced field processing facilities particularly for offshore fields. These pipelines vary in length between hundreds of feet to hundreds of miles, across undulating terrain with varying temperature conditions. Liquid condensation in pipelines commonly occurs because of the multicomponent nature of the transmitted natural gas and its associated phase behavior to the inevitable temperature and pressure changes that occur along the pipeline. Condensation subjects the raw gas transmission pipeline to multiphase, gas-condensate-water, flow transport. This chapter covers all the important concepts of multiphase gas/condensate transmission from a fundamental perspective.