Table of Contents
1 Introduction to Gas Processing
The treatment of Natural gas is a technical procedure. The purpose of gas treatment is to clean the gas by extracting contaminants, fluids, and hydrocarbons (non-methane). In oil and gas terminology the processed gas is called pipeline friendly gas.
The composition of gas depends upon the type of producing well, depth, and area’s geology. Gas processing units clean the contaminant-rich gas by eliminating pollutants like hydrogen sulfide, carbon dioxide, and water. Pollutants like carbon dioxide have commercial value; such contaminants are treated further.
2 Gas Processing: Contaminants in Natural Gas
Methane (CH4) is the main constituent of the naturally produced gas. CH4 is the lightweight and shortest molecule present in the naturally produced gas. The gas produced naturally contains different amounts of contaminants which are:
- Heavy Gaseous Hydrocarbons: normal butane, propane, ethane, isobutane, and pentanes.
- It contains acid gases like CO2, hydrogen sulfide, and mercaptans.
- Other Gases: Helium and nitrogen.
- Naturally produced gas comes with vapours and free water as well. The gas may also contain mercury and chlorides.
- It can also contain naturally occurring radioactive materials like radon and traces of radium.
When the contaminants like H2S, CO2, and N2 exist in the naturally produced gas, it is called acid gas or sour gas.
When vapours and water exist in the gas, it is known as wet gas.
3 Objectives of Natural Gas Treatment
Following are the objectives that are achieved by the processing of the naturally produced gas:
- Remove the content of H2S from the naturally produced gas to make it sweet.
- Remove carbon dioxide and meet customer specifications.
- Eliminate the water content until it does not surpass the limit set by the customer.
4 Reasons for Achieving the Objective of Gas Processing:
Following are the reasons to achieve the objectives of gas processing:
- To produce transportable and pipeline-quality gas.
- To achieve sale-gas conditions set by the customer.
- To enhance the liquid recovery.
5 Types of Gas Processing
Raw naturally produced gas is treated to eradicate all types of contaminants. There are two types of gas processing systems that are generally used in the E&P industry to remove the impurities.
5.1 Glycol Gas Dehydration
As the name dehydration indicates, this process uses adsorption with glycol to eliminate the water vapours and water from the produced gas.
5.2 Amine Gas Sweetening
The process of amine sweetening uses amine to eliminate hydrogen sulfide from naturally produced gas and turns acid gas into sweet and pipeline-friendly gas.
6 Glycol Dehydration
The procedure of produced gas dehydration is achieved in two steps. Firstly, gas is dehydrated, and vapours or free water is eliminated via a chemical reaction that takes place in the absorber of the dehydration package. The second step is the treatment of water-rich glycol to make it lean glycol to be used in the next cycle. Before we begin, let’s talk about the major components of the glycol dehydration unit.
6.1 Components of Glycol Gas Dehydration Unit
a) Inlet Separator
Inlet separator receives the natural gas, and it removes free water that comes with the natural gas. The separator can be two-phase or three-phase depending upon the produced fluid. A gas separator is equipped with mist extractor and wire mesh that separates free water and other particulates from the natural gas.
b) The Contact Tower
The contact tower is the primary workplace of the entire gas dehydration process. In the contact tower, glycol and gas contact, and the gas is dehydrated. There are different factors involved in the designing of the contact tower, like contact tower height and flow rate of the produced gas.
The flow of the stream is counter-current in contact tower. It means that the feed gas enters through the bottom and moves upward while TEG enters from the top and travels downward in the contact tower. When glycol moves downward, and gas moves upwards, they come in contact, and glycol absorbs the vapours and water present in the feed gas, making it dehydrated.
c) The Flash Tank
Flash tank comes in play in the second step of the glycol dehydration process. In the flash tank, lean glycol is flashed at the low pressure. The flashing process allows the volatile components present in the glycol to vaporize.
d) Heat Exchanger (Lean – Rich)
The principal objective of the heat exchanger is to conserve energy. In the heat exchange, glycol coming from regeneration is chilled by the glycol exiting the contact tower. For a chemical reaction to take place properly, the glycol entering contact tower should be cool. The water-rich glycol should be hot for proper stripping of water vapours from the glycol.
e) The Dehydration Unit Regenerator
The regenerator uses the process called fractionation to separate water from glycol. The process is achieved in the reconcentration vessel’s still column. Due to the alteration in temperature, the glycol condenses, and the liquid water vaporizes.
There are different factors involved in determining the size of the regenerator. These factors include the circulation rate of the glycol, reboiler temperature, and the volume of water vapours present in the feed gas.
f) Glycol Pumps
Glycol circulation pumps are one of the essential parts of the dehydration unit. These circulation pumps establish the glycol circulation. Moreover, these pumps increase the pressure of glycol and deliver it to the contact tower for the process of dehydration to begin. Typically, there are two to three glycol circulation pumps installed on a dehydration unit.
6.2 Gas Dehydration Process
If the naturally produced gas contains a large volume of water, the gas must be dehydrated. It is because the excess water will cause problems like corrosion, gas hydrates, and freezing. Gas must be dehydrated to meet pipeline standards. The detailed process of gas dehydration is explained below:
Figure 1: Glycol Gas Dehydration Unit Flow Chart
The wet gas, rich with water, firstly enters the two-phase or three-phase inlet separator to separate the water from the gas. If the natural gas contains free water, a three-phase inlet separator must be used to knock out the free H2O. Although mist remover is installed in the separator, still the feed gas contains a small volume of water vapours.
The wet gas then flows into a contactor vessel from the bottom and moves up. The glycol flows into the contact vessel from the top and moves down. The chemical reaction takes place, and the lean glycol becomes water-rich glycol by absorbing the water and vapours present in the wet feed gas, making it the dehydrated gas. Before the dehydrated gas goes through a metering system into the downstream pipeline, the dry gas enters the glycol cooler to lower the temperature of hot glycol before flows into the contact tower.
The rich glycol exiting from the contact tower flows into a reflux condenser. After the reflux condenser, the water-rich glycol flows into the flash tank where turbulent and unstable components are vaporized.
After flowing out from the flash tank, the water-rich glycol enters glycol filters and the heat exchanger. Water-rich glycol exchanges the heat with the high-temperature lean glycol. It then enters the TEG regenerator with the still column and reboiler, where water is eliminated from the rich glycol via the process of distillation. Moreover, the absorption ability of glycol is increased to fulfil the TEG requirement. Once the rich glycol becomes the lean glycol, the glycol circulation pumps, pump the glycol into the contact tower for the next cycle.
7 Amine Sweetening Process
The amine sweetening process of the naturally produced gas is accomplished in two steps. Firstly, the raw natural gas is purified, and hydrogen sulfide is removed. Secondly, the rich amine is treated to remove the hydrogen sulfide. Before we talk about the procedure of amine sweetening, let’s discuss the surface facilities of the amine sweetening plant.
7.1 Surface Facilities of Amine Sweetening Plant
a) Separator
Inlet separator eliminates contaminants like water, mist, and hydrocarbon condensate and prevents these contaminants from entering the amine system. Two-phase or three-phase separators are used depending upon the fluid being produced by the well.
b) Absorber
The absorber is the primary place where hydrogen sulfide removal takes place. The sour gas and lean amine encounter in the absorber. The gas enters from the bottom and flows to the top through the trays. The lean amine enters from absorber’s top and leaves from absorber’s bottom. The encounter of acid gas and amine turns acid into sweet gas, and amine becomes rich with acid gas.
c) Treated Gas Knock Out Drum
Knock out drum (KOD) is equipped with a demister pad, the dry gas that comes out from the absorber enters the KOD. The primary objective of the gas knockout drum is to eliminate entrained amine coming with the dry gas.
d) Amine Flash Drum
An amine flash drum enables the removal of a portion of acid gas. The amine flash drum is a three-phase horizontal vessel, and it is operated at minimum pressure.
e) Heat Exchanger
The purpose of a heat exchanger is to conserve energy. Its purpose is to reduce the total energy requirements for the amine sweetening process. Low vaporization should take place in a heat exchanger to prevent corrosion/erosion caused by the mixed flow.
f) The Reboiler
The amine solution rich with acid gas leaves the regenerator and flows into the reboiler. The reboiler produces heat energy, and it helps in separating acid gas from the rich amine and turn it into the lean amine.
7.2 Amine Sweetening Unit Explained
If the naturally produced gas has a large volume of hydrogen sulfide, that gas is called sour, and it must be treated before it flows into the pipeline. A large volume of H2S in the naturally produced gas is dangerous for equipment and will cause the pipeline to corrode. Hydrogen sulfide must be removed to prevent this damage. The amine sweetening of naturally produced gas accomplishes the elimination of hydrogen sulfide. The detailed working mechanism of amine plant is explained below:
Figure 2: Amine Gas Sweetening Unit Diagram
The raw natural sour gas from the well enters inlet separator where contaminants like mist, water, and condensate are removed. The acid gas free from contaminants flows into the absorber from the bottom of the contact vessel and flows upward while the lean amine solution enters from the top of the absorber and flows downward.
When lean amine and acid gas come in contact, a chemical reaction takes place, which is exothermic. In this reaction, the amine absorbs the acidic contaminants of feed gas and turns sour gas into sweet gas, while the lean amine becomes rich amine after absorbing the acid gas. The treated gas flows out from the upper part of the absorber while the amine with acid gas flow from the bottom of the absorber. The processed feed gas from the contractor enters the processed gas KOD, where any amine traces in the treated gas are removed, and it is then routed towards downstream facilities.
The rich amine solution flows out from the absorber bottom and into the amine flash drum. In the amine flash drum, the portion of acidic gas is eradicated. The rich amine solution flows out of an amine flash drum and flows into the heat exchanger. Heat exchanger conserves energy and reduces the overall energy needs for the sweetening procedure. The temperature of the acid gas-rich amine is enhanced by the lean amine approaching from the regenerator.
The amine rich with acid gas then flows into the regenerator, which has a condenser and a reboiler. Reboiler is the direct-fired heater where the temperature of amine rich with acid gas is increased to eliminate all acid gases from the amine solution. The amine is then routed towards the heat exchanger. The product of the regenerator is a combination of acid gas & water vapours, and the condenser installed in the ASU handles this stream. In the condenser, the water vapours condense to produce the reflux.
The reflux drum in the amine plant collects the water vapours and acidic gases from the condenser. The acid gas leaves the reflux drum flows towards the disposal system designed for acid gas. The water from the reflux pump is handled by the reflux, which pumps it to the regenerator top.
The lean amine that flows out from the heat exchanger still has an increased temperature. Lean amine finally flows through the lean amine cooler to decrease its temperature. Lean solution cooler uses air to lower the temperature of the lean amine. The lean amine is then sent to the contact tower via circulation pumps for the next cycle.
Mechanical and activated carbon filters are also available on the amine unit. The mechanical filter is placed on the lean amine stream. It filters the solution from solid impurities like sand, iron oxide, iron sulfide, and pipeline dust. The activated carbon filter is installed on the downstream. It filters out water-soluble compounds, unknown foam contributors, and hydrocarbons.
8 Hydrocarbon Dew Point Control Unit
Regulating the hydrocarbon dew point is another important parameter of gas processing to make the meet the pipeline specifications. The temperature at which vapours begin to condense from the gaseous phase is known as the dew point. The hydrocarbon dew point control unit or HDPCU regulates the dew point. The HDPCU is installed in cold areas to prevent the condensation of hydrocarbons.
Figure 3: Hydrocarbon Dew Point Control Unit
HDPCU has the sole purpose of restricting the creation of hydrates in the natural produced gas stream or pipeline. HDPCU performs an equivalent of dehydration, and it is accomplished by injecting the hydrate inhibitor straight in the gas pipeline. Moreover, hydrocarbon dew point control units are developed to use refrigeration or JT (Joule Thomson Effect) to provide the level of cooling as needed.
9 Pipeline Gas Specifications
Naturally produced gas must be processed to fulfil the standards of gas transportation pipeline. The specifications of the gas pipeline are shown in the table below. These pipeline gas specifications ensure that gas is of high-quality, and the customers should get safe and clean gas. Moreover, it should meet the heating values defined in the Wobbe’s index to warrant the optimal operation of gas turbines for electricity generation.
10 Gas Processing: Conclusion
Gas processing is essential if there are a large volume of contaminants are present in the naturally produced gas. Pollutants like water, H2S, CO2, and N2 can damage the pipeline and equipment. They can cause corrosion and create problems like freezing and hydrates. The gas must be treated to make it pipeline-friendly and transportable. Moreover, the treated gas can avoid economic loss and prevent equipment damage.
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