Modern energy efficient and environmentally benign technologies in the gas industry

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Introduction
One of the characteristic features of gas production in the Republic of Kazakhstan is that at most large fields gas is extracted as a by-product from the oil-gas mixture. This leads to dependence of gas production volumes on oil recovery rates.
More than 95 % of all explored gas reserves are concentrated in the western regions of the country, with over 85 % of these reserves located in large oil and gas fields such as Kashagan, Tengiz, Korolevskoye and Zhanazhol, as well as in the Karachaganak and Imashevskoye oil and gas condensate fields. The reserves of the largest fields are as follows: Kashagan - 1,353 billion m3, Karachaganak - 741 billion m3, Tengiz - 510 billion m3 [1].
The process chart of gas treatment can vary greatly depending on the composition of feed gas, product specifications and environmental requirements.
Crude gas coming to the gas processing plant (GPP) from the field contains light hydrocarbons, moisture, sour gases and other components. Before liquefaction, natural gas is treatment and dried. 
The facilities of the gas treatment processing system can be conditionally divided into 3 components [2]:
    Field and Gathering System (GS);
    Onplots and Utilities;
    Offplots and Export Systems.
The gas treatment process flow diagram may include the following units:
    unit of separation, desalting, oil stabilization and associated gas compression;
    unit for redistribution of sour gas between amine treatment of gas units and gas injection units, drying of sour gas before injection to the reservoir, gas treatment from acidic components (H2S and CO2) by means of amine and amine regeneration;
    sulphur recovery unit, Claus process;
    tail gas treating unit (SCOT/Sulfren/Beavon/Superclaus processes, etc.) [3-5].
    dehydration unit of sweet gas to produce sales (fuel) gas, propane and butane;
    produced (sour) water treatment unit.
One of the typical flowcharts for gas treatment is shown in Figure 1.

Figure 1. General process flow diagram of the GPP

At the gas treatment unit, crude oil undergoes separation, desalting and oil stabilization. Gas is separated from oil in three consecutive separators (high, medium and low pressure).
The high-pressure crude gas separated from the oil is sent to acidic components (H2S and CO2) gas removal with amine and amine regeneration.
The hydrogen sulfide-saturated amine solution from the amine treatment unit is regenerated to release hydrogen sulfide (by stripping) and recycle the recovered amine. Sour gas with high hydrogen sulfide content coming out of the amine regenerator is sent to the sulfur recovery unit. The sweet high-pressure gas from the amine treatment unit is sent to a fractionation unit to produce liquefied petroleum gas (LPG) and sales gas, which is sent to the gas pipeline.

Inlet separation

Inlet separation units perform several important functions:
Ensure that equal (process) pressure is achieved for gas coming from different fields.
Remove high-boiling hydrocarbons (C5+) from the gas stream, which prevents liquid hydrocarbons from entering acidic component removal units where such liquids can cause foaming.
The separated liquid hydrocarbons are prepared for subsequent blending with C5+ hydrocarbons from the fractionation unit.
When the raw natural gas enters the gas processing unit, it undergoes a filtration or purification step necessary to remove suspended solids representing reservoir residues and pipeline corrosion and erosion products.
The gas then passes through knocknockout drum where dropping liquids (C5+ condensate, water with methanol, a hydrate formation inhibitor) are removed. The separated liquid is subjected to primary purification from water, hydrogen sulfide and part of mercaptans in a condensate stripper. After treatment in the condensate stripper most of the mercaptans and a small amount of water remain in the liquid phase, so after the evaporation column a block of liquid hydrocarbons drying on molecular sieves is installed to remove the remaining mercaptans. Treated liquid hydrocarbons are then mixed with C5+ hydrocarbons from the fractionation unit. The aqueous phase containing hydrate formation inhibitor is go to the inhibitor regeneration unit [6].
The slug catchers can be of the vessel type (three-phase separators for separation of gas, water and hydrocarbon liquids) or of the multi-pipe type (a series of parallel horizontal pipes connected by manifolds) [7].
Vessel type slug catcher are simple vessel for separation of two phases. Although the separation efficiency of the vessel is not critical for the slug catcher, the vessel volume is important. The vessel must be large enough to accommodate large liquid slugs that form in the pipeline, especially when the pipeline pigging. Since oil and gas pipelines typically have very high pressures, a large vessel must be designed for high design pressures (Figure 2).

Figure 2. Vessel type slug catcher [8]

Multi-pipe slug catchers solve the economic problem of having to design a large buffer volume for high design pressures. To create a buffer volume, multi-pipe slug catchers use large diameter pipe pieces instead of a conventional vessel. Since a pipe is easier to design to withstand high pressures than a vessel, this design is advantageous in this regard. However, a large number of pipes are required to provide sufficient volume, which increases the footprint of the multi-pipe slug                                            catchers (Figure 3).

Figure 3: Multi-pipe slug catcher [9]

The natural gas after the slug catchers undergoes secondary separation to separate the residual liquids, after which it is sent to an acid gas removal unit.

Gas dehydration
Produced natural gas contains moisture, which adversely affects the processing and transportation processes, in particular, some hydrocarbons in the presence of water can form hydrate deposition, which leads to a reduction in the cross-sectional area of pipelines and valves, which can, in the case of complete blockage of the cross-section, cause an emergency situation [6]. Water from gas, like any other component, can be removed by physical methods (adsorption, absorption, membranes, condensation (cold)), chemical methods (CaCl2, etc.) and their infinite hybrids.
The following methods, arranged in descending order of popularity in this list, have found commercial application:
    Absorption - glycol dehydration (Drizo [10-13], Coldfinger [14-16], PETON [17], Stahl column [18]).
    Adsorption - zeolites, silica gels or activated aluminum [19].
    Condensation - cooling with injection of hydrate formation inhibitors (glycols or methanol) [6].
    Membranes - based on elastomers or glassy polymers [20].
    Chemical method - hygroscopic salts usually metal chlorides (CaCl2, etc.) [21].
The overwhelming number of units in the world is based on the first two methods (Fig. 4).

Figure 4. Block diagram of gas production plant with combined gas drying

The Block diagram of the process of natural gas processing with gas drying on molecular sieves is presented in Fig. 5.

Figure 5. Block diagram of a gas production unit with gas drying on molecular sieves

 

Absorption drying is based on the use of liquid absorbents capable of absorbing water from the gas. The most common type of absorption dehydration is glycol dehydration. In glycol drying diethylene glycol (DEG) and triethylene glycol (TEG) are used as absorbents.

Adsorption method of dehydration is based on the use of solid adsorbents. The role of solid adsorbents can be zeolites, silica gels. The choice of adsorbents depends on the composition of the dehydrated gas, as it may contain substances that have a negative effect on the adsorbent. Adsorption method allows to reach deeper dew point on water from -40 to -100 ^o С. Removal of a number of other hydrocarbons besides water depends on the choice of adsorbent.

Table 1 shows the main brands of zeolites and the molecules adsorbed by them [22-24].

 

Table 1: Basic brands of industrial molecular sieves

Molecular sieves grade	Pore diameter, Å	Adsorbed substances
3A	3	H2O, NH3.
4А	4	H2O, NH3, H2S, CO2, SO2, C2H4, C2H6, C3H6, С2H5OH.
5А	5	H2O, NH3, H2S, CO2, SO2, C2H4, C2H6, C3H6, С2H5OH, n-C4H9OH, n-C4H10, C3H8………...C22H46, CCl2F2.
13Х	10	H2O, NH3, С2H5OH, H2S, CO2, SO2, C2H4, C2H6, C3H6 n-C4H9OH, n-C4H10, C3H8………...C22H46, CCl2F2.

The low-temperature separation process is aimed at extracting hydrocarbon condensate and moisture from the gas, bringing it to the dew point at which hydrate formation during transportation is excluded. Low-temperature separation is based on the Joule-Thomson effect (throttling effect).

The advantage of this process is low operating and capital costs, while a significant disadvantage is low recovery of components and reduced efficiency due to changes in gas composition.

The chemical reaction between water and chemicals can be so complete that the hydration products formed will have an extremely low water vapor elasticity. Chemical agents are available that provide almost complete gas drying [25].

However, these agents are very difficult or impossible to regenerate. This fact makes them unsuitable for use as industrial dehumidifiers. However, they are widely used in laboratory determination of gas moisture content.

 

Acid gas removal

The choice of process for acidic components removal from the gas has a significant impact on the economics of the overall sales gas production project, especially if the feed gas contains acidic components in high concentrations.

A number of technologies are available for the acid gases removal:

• regenerative absorption by physical and chemical sorbents;
• regenerative adsorption;
• separation of acid gases on membranes;
• non-regenerative methods.

The choice of the best available technique depends on a number of factors such as the concentration of acid gas components in the feedstock, feedstock flowrate, process pressure, environmental requirements, and others. In order to achieve sales gas specifications, not all technologies can be applied in pure form [26].

In some cases, it is preferable to apply a combination of several methods.

• Absorption processes for natural gas treatment from acidic components remain the most cost-effective for large-scale natural gas production.
• There are many varieties of these processes, organized into three groups [27-30]:
• chemical absorption processes;
• physical absorption processes;
• processes with physical-chemical absorbents.

In chemical absorption processes, acid gases first dissolve in the absorbent and then react chemically with it.

Therefore, absorbents interact with hydrogen sulfide, carbon dioxide and, to some extent, with carbon sulfide to form water-soluble salt and water. Mercaptans and organic sulfur compounds are extracted from the natural gas stream to a lesser extent: first - due to poor solubility of mercaptans in the absorbents. The second ones do not react chemically with the absorbents.

The most well-known process of chemical absorption is amine treatment. Monoethanolamine (MEA), diethanolamine (DEA), diglycolamine (DGA), diisopropanolamine (DIPA), methyldiethanolamine (MDEA) are used as amine solvents. Aqueous amine solvents, with the exception of MDEA, lack selectivity and remove both H₂S and CO₂ from the gas. MDEA has greater selectivity to H₂S, allowing some of the carbon dioxide to pass through, but the use of MDEA reduces the energy cost of regeneration compared to other amines. Activators are added to MDEA for better CO₂ absorption and simultaneous removal of H₂S and CO₂. For example, MDEA is often used in combination with piperazine as an activator [31].

Physical absorption processes involve selective dissolution of acid gases and organic sulfur compounds (COS, CS₂ and mercaptans) in solvents (absorbents). The most common physical solvents are polyethylene glycol dimethyl ether (PGDE), methanol, N-methyl-2-pyrrolidone and propylene carbonate [32-34]. The basic advantage of these processes is that partial solvent regeneration is achieved by depressurizing the throttle, which significantly reduces energy consumption. In some processes, such as Fluor Solvent, regeneration is accomplished by multi-stage throttling and vacuum evaporation of the absorbent [35].

As noted in articles [36-37], physical absorbents have a lower specific flow rate in relation to the gas flow rate compared to amine solutions in the case of high partial pressure of acidic components in the feed gas. At the same time, as the partial pressure of acidic components increases, the consumption of physical absorbents also increases proportionally. However, at deep purification of gas from acidic components physical solvents may not cope with the task, and it will be necessary to introduce additional treatment stages. In some cases, depending on the composition of the acidic components, the combination of physical absorption and additional treatment stages is more cost-effective than individual amine treatment [38].

For gas with a high CO₂ content of up to 32 mol %, a system with two absorbers connected in series and intermediate cooling of the partially saturated absorbent is proposed in [39-40]. The source of intercooling is the throttled saturated absorbent. Reducing the temperature of the absorbent increases its activity and reduces its flowrate.

Mixed natural gas sweetening processes take advantage of both physical and chemical absorbents. Mixed absorbents are used to gas treatment with a high content of acidic components and a deep degree of purification is achieved. Absorption processes of natural gas purification from acidic and sulfur-containing components are given in more detail in articles [41-43].

The basic absorption processes for sweetening of natural gas are summarized in Table 2.

 

Table 2. Absorption processes for removal of acidic components of gas

Process group	Examples	Advantages	Disadvantages
Chemical absorption	Absorption by aqueous solutions of amines (MEA, DHA, DEA, DEA, DIPA, MDEA), Flexorb, Benfield	Deep purification from H2S and CO2. Lower hydrocarbon losses due to their low solubility in absorbents	Low degree of mercaptans removal due to their low solubility in absorbents. High energy intensity of amine regeneration and cooling process
Physical absorption	Selexol, Fluor Solvent, Purisol	Low energy consumption for solvent regeneration. Lower greenhouse gas emissions than amine treating unit	Absorption of part of the hydrocarbons, which reduces the calorific value of the gas. More complicated unit design compared to the amine treatment unit
Hybrid absorption	Sulfinol, Ucarsol, Ecosorb	Almost complete removal of H2S, CO2, COS is achieved	Absorption hydrocarbons

 

However, the quality of absorption gas treating cannot always meet today's high requirements for sulphur emissions from fuel combustion. In the production sales gas as fuel, the sweet gas from the acid removal unit must be subjected to fine cleaning by other processes, such as adsorption on molecular sieves specifically designed to remove sulfur-containing compounds such as carbon sulfide (COS) or                           mercaptans [45-46].

Gas injection

The gas injection system is designed for compression, transportation of moisture-dehydrated raw gas through a system of injection reservoirs and lines to injection wells to maintain reservoir pressure.

At large oil and gas fields, considering the ongoing expansion projects, decision-making in favor of greater gas commercialization requires additional justification considering process characteristics and economic effect of gas injection volumes [47-53].

Since 2004, Kazakhstan has been implementing gas injection programs using associated petroleum gas to maintain reservoir pressure [54].

The projected volumes of sour gas injection will be 31.7 billion m³ in 2025 and 41 billion m³ in 2030 [55].

The associated raw gas intended for injection is dried to remove all water and heated so that the gas temperature at the compressor inlet is above the hydrocarbon dew point. During normal operation, this prevents the formation of hydrocarbon liquid in the pipeline and deposits in the sludge trap on the compressor station raw gas line.

However, condensation cannot be avoided during start-up, shut-down and other cases where the pipeline temperature drops. Therefore, in such cases, provision is made to remove the sulphur-containing liquid if necessary. Liquid condensate accumulated at the compressor station is returned back to processing through the CPM.

The raw gas injection compressor facility consists of a three-stage centrifugal compressor driven by a gas turbine engine, as well as separators at the inlet of each stage, an air cooler between stages, a chiller with a reciprocating compressor at the first stage, and an isolation system for dry seal and buffer gas.

The gas injection process is shown in Figure 6.

Figure 6. General block diagram of gas injection process

Injection of gas back into the oil reservoir allows increasing oil recovery. Operation of the Sour Gas Injection (SGI) at the Tengiz field provides about 25 % of the total TCO oil production [56].

Gas injection also ensures maintenance of reservoir pressure, while the need for associated gas utilization (processing, storage and sale of by-products, sulfur recovery from hydrogen sulfide) disappears [57].

 

Conclusion

Thus, energy efficiency of natural gas purification and dehydration processes depends on the use of a particular type of adsorbent, is dependent on the conditions of the process, primarily on the humidity of the gas supplied to the adsorption unit and the temperature regime of dehydration. Dynamic activity decreases with layer elevation reduction and humidity of dehydrated gas, and small size of adsorbent granules improves the process kinetics, but at the same time increases the layer resistance. The most important parameter determining the absorption capacity of the desiccant layer is the relative gas humidity. The higher the relative humidity, the higher the adsorbent activity. At longer contact time “gas-adsorbent”, and, consequently, lower gas velocity, the depth of drying and the duration of the layer operation up to the moment of slip increase.

 

 

 

 

 

About the authors

Kurmet Gizatullayevich Satenov

KMG Engineering LLP

Author for correspondence.
Email: K.Satenov@kmge.kz
ORCID iD: 0000-0002-6396-913X

Cand. Sc. (Chemistry), Expert, Major Projects Support Department

Kazakhstan, Republic of Kazakhstan Z05H9E8, Astana, Yesilsky district, Business Center “Emerald Quarter”, (Kunaeva str., house 8, block “B”).

Yerlan Suleimen

KMG Engineering LLP

Email: Ye.Suleimen@kmge.kz
ORCID iD: 0000-0002-5959-4013

PhD (Chemistry), Expert, Major Projects Support Department

Kazakhstan, Republic of Kazakhstan Z05H9E8, Astana, Yesilsky district, Business Center “Emerald Quarter”, (Kunaeva str., house 8, block “B”).

Zholaman Abekeshovich Tashenov

KMG Engineering LLP

Email: Zh.Tashenov@kmge.kz
ORCID iD: 0009-0005-6462-8600

Head of KPO Support Services 

Kazakhstan, Republic of Kazakhstan Z05H9E8, Astana, Yesilsky district, Business Center “Emerald Quarter”, (Kunaeva str., house 8, block “B”).

References

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