Gas Sweetening Unit (GSU)​

Natural gas extracted from the reservoir usually contains CO2 and H2S that must be removed

The process of gas sweetening is frequently developed by contacting the sour gas with chemical solvent (amine) in a trayed or packed column: solvent captures contaminants and the treated natural gas will contain a lower content of CO2 and/or H2S according to delivery specs.

Thanks to CMIT extensive experience in the design of sweetening units, including floating applications, the amine circulation rate, the contactor height and the regeneration duty are optimized by proper selection of the amine or blend of amines based on the specific application and by proper design of equipment. CMIT design uses non-proprietary amines.

Gas Dehydration Unit (GDU)

Natural gas extracted from the reservoir usually comes saturated with water. The natural gas shall meet water content specification before being delivered to users by removing excess water. Water removal is accomplished by contacting the gas with a very concentrated triethylene glycol (TEG) solution in a packed column.

CMIT has extensive experience in designing glycol dehydration units for both fixed and floating applications, with optimized glycol circulation rates and contactor heights.

CMIT design guarantees no foaming due to hydrocarbon condensation in the contactor keeping the glycol temperature in the contactor always above the hydrocarbon dew point of the gas.

MEG Reclaimer (Glyco Reclaiming)

MEG (Monoethylene glycol) is injected into humid natural gas coming from wells to inhibit inline hydrate formation during transportation. Salty water contaminates MEG, so it cannot be recycled back into the process, requiring its replacement and exhausted glycol disposal, increasing the opex of the hydrate inhibition.

CMIT MEG Reclamation process is capable of regenerating the glycol by removing salts and impurities from the mainstream. This can be done by means of a batch process or by a full flow process thanks to innovative design based on film technology. The regenerated glycol can be recycled back into the process, minimizing its replacement and the operating costs.

IBMS

In a view of optimizing the requested performance while granting a higher degree of operational flexibility, CMIT has specifically designed the IBMS / Inline BOG Management System.​

IBMS is designed to optimize the BOG condensation. ​

SULPHUR RECOVERY UNIT

Natural gas extracted from the reservoir may contain H2S and other sulphur components, that must be removed.

Sulphur removal is frequently carried out by contacting the sour gas with chemical solvent (amine) in a trayed or packed column: solvent captures contaminants and the treated natural gas will contain a lower content of H2S and other sulphur components according to delivery specs. The absorbed components are then removed from the solvent by stripping with steam at high temperature and low pressure. The resulting acid gas stream is rich of H2S and CO2. Most Sulphur Recovery Units are based on the Claus process, in which approximately one third of the H2S is thermally oxidized to SO2 and then the remaining H2S reacts catalytically with the SO2 to form elemental sulphur. The sulphur is then condensed and recovered from the gas stream. The tail gas can be either incinerated directly or can be subjected to additional treatment to enhance sulphur recovery and reduce SO2 emissions.

CMIT can develop detailed designs of Claus units based on basic design supplied by clients.

CMIT also supplies Sulphur Recovery Units based on redox processes, such as LO-CAT®, thanks to agreements with process licensors. These units are particularly suitable when the flow rate of recovered sulphur is low or the H2S concentration in the sour gas is very low.

MERCURY REMOVAL UNIT
GAS AND WATER

Natural gas extracted from the reservoir may contain mercury, which can cause several issues in gas treating plants and downstream units such as aluminium corrosion in plate fin exchangers employed in cryogenic liquefaction units and catalyst poisoning. In fields producing hydrocarbons, mercury could also be in the produced water and must be removed before water disposal.

Mercury removal from gas is accomplished by chemisorption on a fixed bed of metal sulphide supported on alumina, activated carbon or zeolite. Mercury sulphide (cinnabar), which is the most stable form of mercury, is formed in the reaction. The mercury adsorption mechanism is fast and irreversible.
Mercury removal from produced water is usually performed by means of adsorption on activated carbon.

CMIT design of mercury removal units, which treat gas or water, ensures optimal performance of the system and long adsorbent lifetime by the utilization of beds with strong mechanical resistance, high porous volume and high mercury pick-up capability.

SOUR GAS CONDITIONING

Natural gas that is produced from reservoirs requires some processing to remove the contaminants and meet the sales / product specifications. Contaminants that are usually present in the gas are entrained liquids (both hydrocarbon and free water) and water. Acidic components (CO2 and H2S) and mercury may also be present.

Efficient liquid separation from gas is of utmost importance to ensure trouble-free operation of gas treating units, for example to avoid foaming in the columns of gas dehydration and gas sweetening units. CMIT designs optimize the configuration of gas/liquid separators and gas/liquid filter coalescers by proper specification of the internals and proper design of the inlet piping to meet the separation performance required by the specific application.

Water removal can be accomplished by contacting the gas with a very concentrated triethylene glycol (TEG) solution in a packed column or by regenerative adsorption of water on molecular sieves when very low dry gas water content is required, e.g., when the dry gas must be subsequently liquefied.

CMIT has extensive experience in designing glycol dehydration units for both fixed and floating applications, including sour gas dehydration units.
CMIT design of TEG Dehydration Units guarantees no foaming due to hydrocarbon condensation in the contactor keeping the glycol temperature in the contactor always above the hydrocarbon dew point of the gas and minimized glycol degradation due to proper design of the glycol reboiler and the glycol filters and to the provision of pH controller injection for sour gas dehydration units.

Acidic components (H2S and CO2) are usually removed by contacting the sour gas with chemical solvent (amine) in a trayed or packed column: solvent captures contaminants and the treated natural gas will contain a lower content of CO2 and/or H2S according to delivery specs. The absorbed components are then removed from the solvent by stripping with steam at high temperature and low pressure. The resulting acid gas stream is rich of H2S and CO2.

Thanks to CMIT extensive experience in the design of sweetening units, including floating applications, the amine circulation rate, the contactor height and the regeneration duty are optimized by proper selection of the amine or blend of amines based on the specific application and by proper design of equipment. CMIT design uses non-proprietary amines.

The acid gas stream that leaves the stripper shall be treated to recover sulphur and comply with the environmental regulations. Most Sulphur Recovery Units are based on the Claus process, in which approximately one third of the H2S is thermally oxidized to SO2 and then the remaining H2S reacts catalytically with the SO2 to form elemental sulphur. The sulphur is then condensed and recovered from the gas stream. The tail gas can be either incinerated directly or can be subjected to additional treatment to enhance sulphur recovery and reduce SO2 emissions.

CMIT can develop detailed designs of Claus units based on basic design supplied by clients.

CMIT also supplies sweetening units based on redox processes, such as LO-CAT®, thanks to agreements with process licensors. These units are particularly suitable when it is not required to remove CO2 from the gas, the flow rate of recovered sulphur is low or the H2S concentration in the sour gas is very low.

Mercury removal from gas is accomplished by chemisorption on a fixed bed of metal sulphide supported on alumina, activated carbon or zeolite. Mercury sulphide (cinnabar), which is the most stable form of mercury, is formed in the reaction. The mercury adsorption mechanism is fast and irreversible. CMIT design of mercury removal units ensures optimal performance of the system and long adsorbent lifetime by the utilization of beds with strong mechanical resistance, high porous volume and high mercury pick-up capability.