Understanding the Core Process Modules and Objectives in Natural Gas Processing

Natural Gas Processing is the essential sequence of operations required to condition raw natural gas for long-distance transport and consumer use. The core objective is the separation of valuable products and removal of contaminants, including liquid hydrocarbons, water, and acidic compounds like hydrogen sulfide and carbon dioxide.

The specific configuration of Process Modules – such as phase separation, acid gas treating, dehydration, and liquid recovery – is customized during the design stage. This optimization depends fundamentally on the gas stream’s composition, the required sales specifications, and the logistics of the gas field’s location.

Introduction

Raw natural gas after transmission through the field-gathering network must be processed before it can be moved into long-distance pipeline systems for use by consumers. The objective of gas processing is to separate natural gas, condensate, noncondensable, acid gases, and water from a gas-producing well and condition these fluids for sale or disposal. The typical process operation modules are shown in Figure below. Each module consists of a single piece or a group of equipment performing a specific function. All the modules shown will not necessarily be present in every gas plant. In some cases, little processing is needed; however, most natural gas requires processing equipment at the gas processing plant to remove impurities, water, and excess hydrocarbon liquid and to control delivery pressure. The unit operations used in a given application may not be arranged in the sequence shown in Figure below, although this sequence is typical. The choice of modules to be used and the arrangement of these modules are determined during the design stage of each gas-field development project.

Unfortunately, at the individual module level the design may be sound and the operation correct but could result in a poor gas processing facility.

The reason is that each module has varying characteristics under varying loads, which can result in a type of internal incompatibility. For instance, a given unit module may require a particular inlet composition to produce the desired output. If a previous unit does not maintain this, the downstream unit may not operate satisfactorily. Thus, the fault might not lie so much with that unit but with total plant design, even though the unit module is usually blamed.

The individual unit modules of Figure above are briefly reviewed here with greater details to follow in subsequent chapters.

Process Modules

The first unit module is the physical separation of the distinct phases, which are:

• typically gas,
• liquid hydrocarbons,
• liquid water,
• and/or solids.

Separation of the Gas Produced in Field from Unnecessary ComponentsPhase separation of the production stream is usually performed in an inlet separator. Inlet gas receiving is complicated by the fact that transmission lines supplying the plant typically operate with two or three phases present and consequently liquid slugging is common. Slugs are normally formed from elevational changes in the inlet supply pipes, changes in Demand, Supply, and Market Outlook of Liquefied Gas Global Tradegas supply flow rates, and changes in pressure and temperature during transmission. Slug flow may even be encountered in horizontal pipes under steady-state conditions if the flow regime is not properly selected. The arrival of “slugs” at production or processing equipment impacts the operation of production facilities negatively, causing both mechanical problems (due to high velocities and momentum) and process problems (increasing liquid levels, causing surges and trips). In some cases operators can minimize liquid accumulation by managing fields and pipelines in such a way as to create a suitable fluid flow regime (i. e., mist flow regime) in which the gas velocity is high enough to keep liquids dispersed continuously. While it is desirable to design the flow lines to avoid slugging, in practice this can be difficult while maintaining the ability to turn down the pipeline flow rate. In these cases, consideration should be given to providing suitable process equipment to diminish the effect of slugging. Gas pipelines have typically used slug catchers to dissipate the energy of the liquid slugs, to minimize turbulence, to ensure that the gas and liquid flow rates are low enough so that the stratified flow regime and subsequently gravity segregation can occur. The slug catcher is designed to separate gas, hydrocarbon condensate, and inlet water. The gas stream is sent to the inlet separators.

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The separators usually contain vane elements to aid in the coalescence of liquids. They may also include filters to remove particulates and may be followed by suction scrubbers if compressors are needed to bring low-pressure gas up to high pressure for further processing operations. The liquids that collect in the slug catcher flow to a three-phase separator from which the two liquid phases, hydrocarbon condensate and water/methanol or water/glycol phases, are outputs. Overhead gas from the three-phase separator is recompressed where necessary for use as fuel gas. More detailed information about phase separation is presented in article “Phase Separation”.

Hydrocarbon condensate recovered from Mastering Natural Gas Fundamentals Properties Sources and Transport Insightsnatural gas may be shipped without further processing but is typically stabilized to produce a safetransportable liquid. Unstabilized condensates contain a large percentage of methane and ethane, which will vaporize easily in LNG IMO Tanks/Containment Systemsstorage tanks.

Stabilization is the full removal of light fractions from the condensate, usually achieved by distillation. Stabilized liquid will generally have a vapor pressure specification (Reid vapor pressure Vapour pressure at 100 °F. Reid vapor pressure is a standard indicator of volatility and a key quality control factor, particularly when considering condensate storage.x of <10 psi), as the product will be injected into a pipeline or transport pressure vessel, which has definite pressure limitations. Condensate stabilization is discussed in article “Condensate Stabilization”.

The next step in natural gas processing is acid gas treating. In addition to heavy hydrocarbons and water vapor, natural gas often contains other contaminants that may have to be removed. Carbon dioxide (CO₂), hydrogen sulfide (H₂S), and other sulfur-containing species such as mercaptans are compounds that require complete or partial removal. These compounds are collectively known as “acid gases“. H₂S when combined with water forms a weak sulfuric acid, whereas CO₂ and water form carbonic acid, thus the term “acid gas“. Natural gas with H₂S or other sulfur compounds present is called “sour gas“, whereas gas with only CO₂ is called “sweet“. Both H₂S and CO₂ are very undesirable, as they cause corrosion and present a major safety risk. Treating processes for receiving these components are covered in article “Acid Gas Treating”.

Depending on the pressure at the plant gate, the next step in processing will either be inlet compression to an “interstage” pressure, typically 300-400 psig (compression is discussed in article “Natural Gas Compression”), or be dew point control and natural gas liquid recovery. Water dew point control is required to meet specifications and to control hydrate formation. Gas hydrate formation is a major concern for engineers in pipeline and Natural Gas Transportation in the Form of Hydrate Pellets (NGHP)natural gas transportation industries as it causes choking/plugging of pipelines and other related problems. Methods of preventing hydrate formation in the plant include lowering the hydrate formation temperature with chemical inhibition or dehydration to remove the water. Gas dehydration is discussed in detail in article “Natural Gas Dehydration”.

Hydrocarbon dew point or hydrocarbon liquid recovery involves cooling the gas and condensing out the liquids. Hydrocarbon dew point control can be either dehydration followed by cooling/condensation or by a combination of inhibition/cooling/condensation processes. Refrigeration is performed either by autorefrigeration due to a pressure drop across a valve or by an external mechanical refrigeration process. The temperature to which the gas is cooled depends on whether it is necessary to meet a sales gas hydrocarbon dew point specification or whether substantial liquid recovery is desired. Three situations motivate maximum condensate recovery. The first is the desire to maximize condensate production when processing associated gas. The second situation occurs when processing retrograde condensate gas; here the objective is to recover the condensate and reinject the gas into the formation. Third, in some markets the natural gas liquids (NGLs) produced from the condensate may be more valuable as liquid products than as sales gas components, i. e., their recovery will yield a better profit. Whether to leave maximum NGLs in the gas stream (but still attaining sales hydrocarbon dew point specification) or to recover them as liquids is purely an economic decision made by comparing their value as heat versus the equivalent value as liquid chemical feedstock. If the equivalent liquid value is lower than the gas, NGLs should be left in the gas to the extent as possible. However, if the equivalent liquid value is higher than the LNG and Domestic Gas Value Chainsgas value, then liquid recovery should be maximized. Natural gas processing for liquid recovery is discussed in article “Natural Gas Liquids Recovery”.

If gas is produced at lower pressures than typical sales Piping System of pressure vessels on gas tankerspipeline pressure (approximately 700-1 000 psig), it is compressed to sales gas pressure.

Transport of sales gas is done at high pressure in order to reduce pipeline diameter. Pipelines may operate at very high pressures (above 1 000 psig) to keep the gas in the dense phase thus preventing condensation and two-phase flow. Compression typically requires two to three stages to attain sales gas pressure. As stated previously, processing may be done after the first or second stage, prior to sales compression. More details are available in article “Sales Gas Transmission”.

Where there is no available gas pipeline, separated associated gas may be flared. The ability to flare depends on regulations as well as the field location. Increasingly in such cases, separated gas is being conserved by compression and reinjection into producing formations for eventual recovery and sales. Also, in gas condensate reservoirs, the gas is often reinjected, or “cycled“, to enable higher net recovery of valuable liquid hydrocarbons from the reservoir.

Scope of Natural Gas Processing

The important factors that usually determine the extent of gas processing include the processing objectives, the type or source of the gas, and the location and size of the gas fields.

Processing Objectives

If the natural gas is transportated by pipeline, the processing installation must be designed to meet either transport or final specifications. Processing of a gas stream may have one of the following three basic objectives.

• To produce a sales gas stream that meets specifications of the type shown in Table below. These specifications are mainly intended to meet pipeline requirements and the needs of industrial and domestic consumers.
• To maximize NGLs production by producing a lean gas stripped of most of the hydrocarbons other than methane.
• To deliver a commercial gas. Such gas must be distinguished by a certain range of gross heating value lying.

Effect of Gas Type in Field Processing

The gas composition of the field is the most important issue in choosing a processing scheme. In other words, depending on the type of reservoir and the composition of the produced gas, the Gas Handling Equipment for Efficient Gas Processinggas processing plant may contain extensive facilities for the processing of the associated liquefiable hydrocarbons.

Typically, associated gas is very rich in liquefiable hydro-carbons and must undergo NGL and condensate recovery to meet hydrocarbon dew point or minimum heating value requirements. The gas processing scheme will also be dictated by the format of the sales contract and its specifications. The contract may be totally different for each customer depending on the composition and amount of gas, plant recoveries, and the contractual preferences of the customer.

Location of the Gas Field

The productivity of a gas reservoir can vary greatly and depend primarily on type, location, and age. Because the location and output of the wells can vary widely, then not surprisingly, the systems that have been designed to collect and process this output also vary widely.

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There are at least two aspects of location that are important: remoteness and local temperature variation. Temperature affects the tendency for hydrate formation in the gas gathering network. Offshore platforms and “outbacks” are examples of remote locations. Even these locales are not strictly comparable because one is sea based vs dry land based. For the sea-based facility the produced fluid from each wellhead flows via a flow line into a manifold and from there to the process facilities located on the platform deck. Ship platforms are extremely limited with respect to size and allowable weight and only those operations absolutely needed are performed. Facilities on the Offshore terminal for transshipment of liquefied gasoffshore platform will generally process the gas to produce a low water content hydrocarbon stream for export to shore through the subsea pipelines. This process ensures minimal corrosion, as well as minimizing the potential for hydrate formation in the raw gas pipeline. A dry-land outback facility has essentially unlimited area available and can support operations not practical or desirable offshore, such as treating or processing involving fire hazards.

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