Gas Process Simulation - Coursework Example

Gas process simulation NGL Process Simulation May 19 Table of Contents Executive Summary 4 2. Background 4 3. Best Technology Solutions 5 3.1 Natural Gas Liquid Expanders - Turbo-expander technology 5 3.1.1Process Description 5 3.1.2 Plant Capacity 6 3.1.3 Large Scale NGL Expander Design 8 3.1.4 Equipment needed for the technology 9 3.2 CRYO-PLUS technology 11 3.2.1 The benefits of CRYO-PLUS technology 13 3.2.2 CRYO PLUS Process 14 4. Other available Technology solutions 18 4.1 Methanol from Natural Gas 18 4.2 Claus Sulfur Recovery 18 4.3 Ammonia Production 19 4.4 Cryogenic Oxygen Plants 19 4.5 Fluid Catalytic Cracking (FCC) 19 4.6 Natural gas reforming Steam Methane Reforming (SMR) technology 20 4.7 KBR SCORE (Selective Cracking Optimum Recovery) -Ethylene technology 20 4.8 The Controlled Free Zone (CFZ) technologies 20 5. Conclusion 22 List of Figures and Tables Figure Fig. 1. CRYO-PLUS in Natural Gas Processing 13 Fig. 2. Block flow diagram of CRYO-PLUS processing 15 Fig. 3. Schematic of the CRYO-PLUS recovery process 17 Table Table 1 NGL expander operating costs and utility requirements 9 Table 2 Large-scale NGL Expander equipment list 10 1. Executive summary The natural gas flowing into the gas pipeline transportation system in many countries meets certain quality measures for proper pipeline operation. Therefore natural gas generated at the wellhead comprises of contaminants mixed with natural gas liquids and must be processed. It must be purified prior to safe delivery in the pipeline system (transported over long distances and under a high pressure) to the consumer. Natural gas that do not conform to some particular pressures, BTU content limits, gravities and water content levels will give rise to pipeline operational problems and impairment, or in extreme cases rupture the pipeline. 2. Background Natural gas that is extracted from sources consists of much greater quantity of methane, and, small traces of Natural Gas Liquids (NGL). These are in most cases ethane and propane, but also comprise of some butane and aliphatic hydrocarbons containing less of carbon content. In cases where the amounts of these materials are not high; they to a small extent increase the heating value of the gas and there is a chance that they may remain in the natural gas. On the other hand if the amounts of such gases is less such that the condensation may happen within the transmission pipeline or there could be a significant influence on the suitability of the gas for various applications (typically, the measurement is done in terms of the heating value and the associated Wobbe number), the pipelines may not buy the gas from manufacturers without prior treatment to retrieve the heavy hydrocarbons. Busby (2003) reiterates that as economies grow many industries grown exponentially providing a rich market for petrochemical feed stocks (ethane and heavy unsaturated hydrocarbons separated from the natural gas). From an economic viewpoint the chemical feedstock and heating value factors of the generated hydrocarbons determine the profitability of NGLs extraction due to the cost of producing natural gas for pipeline transport (Busby, 2003). 3. Available technological solutions 3.1 Natural Gas Liquid Expanders - Turbo-expander technology 3.1.1Process Description Circulating heavy hydrocarbon liquids in early gas processing facilities were utilized to absorb the lighter gas constituents in lean gas absorber plants. The advancement in turbo machinery technology resulted to the introduction of newer cryogenic processes. As of late, these turbo-expander processes have dominated over other technologies in NGL extraction. According to Kelly (2006), Turbo technology has undergone tremendous development mainly to allow the expander plants to have sensible recoveries and economics when eliminating ethane (leaving it in the gas) while recovering at least 90% of the propane and heavier hydrocarbon components. This is absolutely essential so as to make such plants to continue operating when economic factors favour leaving the hydrocarbon ethane in the pipeline gas (Kelly, 2006). Currently there are several patented schemes that ameliorate upon the original turbo-expander design with the sole purpose of in order to enable this mode of operation. Many energy companies such as Ortloff, IPSI LLC, Fluor and ProQuip provide NGL expander plants. Kelly (2006) points out that mechanical refrigeration scheme are the essential procedure for the extraction of NGL from natural gas. Basically there is absence of chemical reactions taking place. Natural gas is introduced continuously at a pressure of 600 psi and replaced with cold gas that exits from the crest of demethanizer equipment. It’s then moved to a cold separator where condensed liquids are removed. These condensed liquids are to a greater extent cooled and conveyed to the demethanizer column as cold reflux. Meanwhile the turbo expander expands the gas exiting the cold separator, cools and distils substantial quantities of liquid for column reflux. The demethanizer equipment precisely extracts both the gas feeds and cold liquid to the column. The overhead gas is highly concentrated in methane with some ethane if desired. The lower side of demethanizer column will be mainly ethane and propane. Depending on the constituents of the gas and the NGL product specifications, it may be absolutely essential in some plants to additionally distil the liquid to retrieve butane and heavier hydrocarbon components (Kelly, 2006). 3.1.2 Plant Capacity The plant needed for processing 330MMscf/d at 600 psig pressure and 100 Deg F temperatures is constructed to correspond in size with the quantities of NGL anticipated in the natural gas feed. Normally natural gas comprises of NGLs at diversified concentrations depending on the producing regions. Distinct regions may contain varying quantities of natural gas being produced due to factors such as the age of the field and the number of wells being drilled. 3.1.3 Large Scale NGL Expander Design Table 1 shows the equipment list for large scale design for Natural Gas Liquid Expanders. The large scale process for NGL recovery differs slightly from that of the smaller scale NGL systems applying similar turbo-expander technology. The main difference is heat incorporation where the larger scale systems have the capacity to have extra heat exchanger systems to reduce the thermodynamic drawbacks associated with the cooling of the stream. Consequently, the complexity of the entire design is increased; thus raising the capital costs and the investment per SCFD of feed reduces. The feed gas enters the plant at 100°F and 600 psig (stream). If the inlet gas has some traces of sulphur compounds that may hinder the product streams from conforming to specifications, the sulphur compounds are retrieved by a suitable pre-treatment of the inlet gas. Additionally, the feed stream is generally dehydrated upstream to keep hydrate ice from forming under cryogenic considerations. Solid desiccants are generally utilised for this function and are not included here. The feed gas is cooled in numerous heat exchangers of the plant. The resulting products are cool residue gas at –86°F followed by bottom liquid product at 62°F then demethanizer boiler liquids at 39°F, and finally demethanizer side boiler liquids at -32°F. The cooled stream then goes into high pressure separator (V-1) at -22°F temperature and 885 psia pressure where the vapor (gas stream) is split from the condensed liquid. The gas vapor from separator (V-1) moves into the turbo-expander (K-1). Within the expander mechanical energy is recovered under extreme pressure feed. The vapor is then expanded rapidly from 885 psia to 312 psia pressures, with the effects of expansion causing a cooling of the expanded gas stream to a temperature of about 100°F. General commercially obtainable expanders have the capacity of recovering approximately 80-85% of theoretical energy available in a perfect isentropic expansion. The energy retrieved is used to power the centrifugal expander compressor (K-2). The expanded semi-condensed gas stream is further moved briefly to the low-pressure separator (V-2). The gas vapor stream from V-2 is separated into two streams. Approximately 60% of the total gas vapor goes via the cold gas exchanger (E-1) against a section of the cold distillation stream, causing more cooling and condensation. The more cooled and partly condensed stream is consequently moved to the distillation column normally at the topmost mid-column feed point. The 40% of the gas vapor remaining from V-2 is flowed to the demethanation tower (T-1) at a second topmost mid-column feed point. The condensed liquid stream from V-2 is delivered forth in the NGL pump (P-1) before the feeding of the distillation column at a third topmost mid-column feed point. A significant quantity of the high-pressure residue gas is drawn back from the main residue flow stream to assume the top distillation column feed position. The recycle gas stream together with small quantities of the cool residue gas goes via a series of heat exchangers and undergoes cooling to a temperature of about148°F. As the stream expands to equal the demethanizer’s operating pressure of 324 psia, it is accordingly cooled to a temperature of about -158°F. The topmost mid-column feed position of the fractionation tower receives additional liquids resulting from the cooling and partial condensation of vapor. In the tower, these liquids play the role of a reflux on the vapor rising up the tower. As a result the amount of vapour to be purified by the top reflux stream decreases corresponding to decreased quantities of top reflux feed needed to attain the desired C2+ component recovery level. Design Assumptions The large scale NGL design is based on a turbo-expander processing plant for the recovery of NGL from natural gas. Kelly (2006) shows that a HYSYS simulation model is applied to size equipment. Costs are affirmed by credible party like Trimeric Corporation utilizing vendor quotations and PDQ$ costing program. Large scale units are characterized by stable feed rates and qualities, as they are usually built in an area with a very firm feed supply. Also, product requirement is usually locked in and incorporated with petrochemical facilities. The design flexibility incorporated into the small scale unit for processes like feed treating, additional heating and cooling, is generally not necessary in the large scale unit (Kelly, 2006). Operating costs and utility requirements for large scale NGL expander design The table below shows the basis for the operating costs and utility requirements for large scale NGL expander design. Table 1 NGL expander operating costs and utility requirements Operating Variable Large Scale Comments Cooling Water (gal/hr) 52,568 Inter-stage compressor prerequisites Catalyst Mol Sieve (lb) N/A ~$2.50/lb, lifespan will vary Electricity Use (MW) 27.9 Product compression is the primary cost As well as the listed items above, natural gas is additionally utilised for other diverse heating needs, such as furnaces and high temperature oil system reheating. Usually, the fuel gas generated from the expander system is utilised for this activity, therefore there is no external natural gas is bought particularly for plant use. As previously indicated, the feed for natural gas may need extra treating making it necessary for both drying and particulate clean-up units to be incorporated into the small scale NGL expander designs. Large scale design units contain more stable and dependable feed sources that may have treating upstream of the processing facility and may not necessarily need these extra units to be present. Information given by vendors for the large scale designs exclude some of the less important pieces of equipment, which is the reason as to why there is no molecular sieve requirements included for the large scale unit. 3.1.4 Equipment needed for the technology Gas processing equipment needed for the processing plants, ensures that pipeline tariff requirements are conformed to. The equipment ensures that the natural gas: Is within a specific BTU content range Is delivered at a determined hydrocarbon dew point temperature level, below which any vaporized gas liquid in the mix will have a tendency to condense at pipeline pressure. Contain negligible quantities of elements such as oxygen, H2S, CO2, and water vapour. Do not have liquid water and some traces of particulate solids that can cause damage to the pipeline and its associated operating equipment. Table 2 Large-scale NGL Expander equipment list Item No Description Type Quantity Size Materials Exchangers Area(sq.ft) E-0 Cold Gas/Gas Exchanger Shell/Tube 1 10,120 Aluminum E-1 Condenser I Shell/Tube 1 16,145 Aluminum E-2 Condenser II Shell/Tube 1 15,730 Aluminum E-3 Condenser III Shell/Tube 1 Aluminum E-4 Compressor Discharge Cooler Shell/Tube 1 CS E-5 Gas/Liquid Exchanger Shell/Tube 1 CS E-6 Warm Gas/Gas Exchanger Shell/Tube 1 CS E-7 Gas/Liquid Exchanger Shell/Tube 1 CS E-8 Cold Gas/Gas Exchanger Shell/Tube 1 Aluminum E-9 Cold Gas/Liquid Exchanger Shell/Tube 1 13,324 Aluminum Columns, Vessels & Tanks T-1 Demethanizer Tray Column 1 LTCS V-1 High Pressure Separator Horizontal 1 CS V-2 Low Pressure Separator Horizontal 1 SS Pumps, Compressors & Blowers HP P-1 NGL pump Centrifugal 2 400 SS P-2 Reflux pump Centrifugal 2 12 SS K-1 Expander Turbine 1 5180 CS K-2 Expander Compressor Turbo-Expander 1 5180 CS K-3 Residue Compressor Centrifugal 1 26,624 CS 3.2 CRYO-PLUS technology CRYO-PLUS technology provides the best technology solution to recover most of the liquid products. Advancement in technology has led to the development of integrated designs for cryogenic NGL recovery plants that are appropriate for co-production of an LNG stream with limited or no loss in NGL recovery. Figure 1 shows Block flow diagram of CRYO-PLUS processing plant operated by Linde group. It uses technology from Linde Process Plants, Inc. and has a gas processing capacity of 330 MMSCFD. The inlet gas has NGL content of about 4 gallons per MSCF. Roughly 90% of carbon dioxide, 98% propane and 99% of butane are retrieved as NGLs. The loss (shrinkage) of feed natural gas due to processing is approximately 11% of the inlet gas feed input. Higher Recovery with Less Energy It is specifically designed to be utilized in natural gas, or shale gas applications. LPP has the patent for CRYO-PLUS technology process that recovers greater quantities of ethane and other heavier components with little energy need than conventional liquid recovery processes. Higher Flexibility/ adaptability According to Linde Process Plants, Inc. (2014), enhanced CRYO-PLUS technology is more sturdy and strong in form making it flexible over a wide range of pressure and feed constituents. This feature is of great significance especially for treatment of wet shale gas, which is highly regarded for having huge compositional unevenness over time. This technology solution gives an increased level of ethane recovery in ethane specific recovery mode, and a rich propane recovery in ethane elimination mode. The process has the capacity to rapidly and easily vary between these two modes of operation (Linde Process Plants, Inc. 2014). Reduced Feed and Product Compression The proprietary natural gas processing is modified to achieve maximum operation efficiency leading to lower inlet pressure necessities while still giving the same product release pressure. Reduced Fuel Consumption The CRYO-PLUS NGL processing demands less power than an ordinary gas processing plant. CRYO-PLUS greatly enhances the recovery of C2+ constituents, thereby permitting gas processors to fulfil the heating value expectations for the gas while increasing profits to the venture. The ethane and heavier hydrocarbons regained are valuable inlet feeds for crackers giving rise to olefins and later for polyethylene and polypropylene processing plants. Where is CRYO-PLUS used? CRYO-PLUS technology is the ideal solution used to process any type of natural gas comprising of hydrocarbon liquids. According to traditional NGL processing, the gas processing industry has been characterized by the use of Dew Point Control and other gas processing technology plants to remove impurities from natural gas so as to conform to pipeline requirements. The pipeline requirements entail the prevention of liquids formation in pipeline and ensure large possible quantity BTU content. Regrettably, these systems retrieve utmost 80% of the C2 and some of the C3+ can get through into the gas. These C2+ liquids may allow for an increased sales value more than the pipeline gas itself. Figure 1 below depicts a block diagram for a natural gas processing flow scheme, and shows where CRYO-PLUS technology is incorporated within the operation system. Fig. 1 CRYO-PLUS in Natural Gas Processing (2014) 3.2.1 The benefits of CRYO-PLUS technology The desirable C2 and C3 recoveries are the primary purpose for this technology. The relative values of the retrieved components, the expected economic payout, the fuel gas, available compression and utilities are some of the factors considered for satisfactory hydrocarbon recoveries. CRYO-PLUS technology operates in two modes namely; ethane recovery mode and ethane rejection mode. When operated in ethane recovery mode CRYO-PLUS recovery for C2 is usually 96%, with a 100% recovery of C3 and heavier hydrocarbon components. On the other hand the corresponding recovery values for ethane rejection mode are 98% or more for C3, and 100% of the heavier hydrocarbon components. When running in ethane rejection mode, the CRYO-PLUS technology recovers about 25,520 BBL/Day of mixed C2+ liquids. A processing plant can sell the higher BTU natural gas stream minus any treatment. This is generally not possible due to pipeline transportation requirements, but there is possibility of minimal treatment prior to disposal of the liquids. The disposal of these high BTU gas improves the economics of scale. The composition of the recovered liquid stream mirrors the fuel gas streams that form the CRYO-PLUS feeds. Alternatively, ethane, propane and butane can be separated by fractionation and each can be flowed to a separate process for further purification or merely disposed of to a purchaser as chemical feedstock. The same applies to operations in ethane recovery mode. In this case, the CRYO-PLUS technology retrieves about 35,630 BBL/Day of mixed ethane liquids. Due to higher ethane content, the mean value of this mix may be smaller. Jones and Pujadó (2006) provide yet another more significant benefit of CRYO-PLUS technology comes in handy from the gradual change in the fuel gas composition after getting rid of the C3 and C4 components. Due to the high heating value of the C3 and C4’s higher NOx emissions may take place as a result of high temperatures in the furnace. The elimination of C3 and C4 constituents from the fuel gas in turn reduces the NOx emissions. This removal is solely responsible for the significant NOx reduction modification cost in the subsequent combustion process. The overall effect of such reduced NOx emissions is greater compliance and less expensive process to the end user (Jones and Pujadó, 2006). 3.2.2 CRYO PLUS Processes CRYO-PLUS is basically a cryogenic recovery technology which uses a turbo-expander to regain energy while cooling the feed gas. CRYO-PLUS technology is completely distinct in its capacity to process low-pressure gas streams and get high recoveries with little compressor and/or refrigeration horsepower than traditional or competing cryogenic processes. A simple description of the unit operations is as shown below. Fig. 2 Block flow diagram of CRYO-PLUS processing (2014) Feed Conditioning To protect the unit against adverse operation conditions, feeds may initially pass through a coalescing separator specifically designed to get rid of liquid droplets and solid particles that may be brought over from preceding processes. CRYO-PLUS is designed to accommodate small amounts of H2S and CO2 which are undesirable. These compounds are removed in the feed conditioning phase where absorption process takes place by utilising an amine treating unit for acid gas components elimination. Feed Compression The next phase is to compress the feed stream to 600 psig except when it is already at high levels of pressures. The integration of an air cooler (cooling water) to the gas processing plant, lowers the temperatures of the gas thereby cooling the gas at lower levels of the compressor hence remove the heat of compression. This heat can also be alternatively utilized as a heat source for fractionation as provided for by both temperature driving force and process heat balance. Dehydration In this phase the levels of water in the gas is reduced to an acceptable level. This process ensures that ice and hydrate do not form in the cryogenic section of the process. The molecular sieve desiccant beds operate in batch enabling an effective adsorption where several) adsorption beds are utilized. It follows that either one or more of the desiccant beds are being renewed to restore their capacity while the other beds are concurrently drying the feed gas. A recycle component part of the dry gas can be heated and utilized for regeneration of the desiccant beds in order to dispel the adsorbed water. The cooling of this stream jet condenses the retrieved water, before being recycled and combined with the feed gas. Only on a once through basis a good percentage of the residue gas may also be utilised for the regeneration. Away from the adsorption beds, the gas goes via a dust filter to retrieve any particulate matter carried over ahead of subsequent processing. Feed Cooling This activity occurs after dehydration where the feed gas flows into the cold segment of the process. A heat exchanger made of brazed aluminium plate provides a cooling environment where heat exchange occurs between the cold separator liquids and residue gas. The gas may undergo further cooling by use of external refrigera­tion before it gets to the cryogenic part of the process. This further cooling is not mandatory although it brings much better effect to the feed gas. Cold Separation This process is closely linked to the feed cooling. In this stage, the feed gas is partly condensed and brought to a liquid separator. Subsequently, the liquid flows through the inlet exchanger so as to bring out a cooling effect to the feed gas before getting into the deethanizer for fraction­ation. The vapour runs to the inlet of the expander. Due to gas thermodynamics the gas expands giving rise to the energy needed for the compression. The simultaneous expansion and getting rid of energy cools the gas to a greater extent and induces additional condensation. Afterwards the expander eliminates the products into the first tower of fraction­ation process. This is a two-phase fraction­ation process that enables heat transfer between columns making it possible to have a higher gas recovery with less horsepower consumption. It is this configuration that gives CRYO-PLUS its advantages over other NGL processing technologies. Fig. 3 Schematic of the CRYO-PLUS recovery process (2014) The two tower processing scheme generates a residue gas and a deethanized liquid product. The residue gas pressure coincides with that of the fuel system. Succeeding the replacement of the feed gas in the inlet cooling phase, the residue gas gets to the fuel system in a dry, stable heating value condition. The liquid product from the fractionation system is the retrieved C2 or C3 liquid hydrocarbons. The liquid frequently goes through additional processing, most commonly additional fractionation in the succeeding columns. For C3 retrieval, the liquid stream is generally debutanized. The C3 and C4’s may soon afterwards be flowed to an alkylation process, or be separated from the C3 proceeding to polymerization and only the C4’s getting to alkylation feed. For C3 retrieval, a depropanizer usually precedes the debutanizer 4. Other available technology solutions 4.1 Methanol from Natural Gas The most frequent commercial technology for methanol recovery is the Low Pressure Methanol synthesis route initiated by Synetix. This is a catalytic reaction process using elements such as copper, zinc oxide and alumina catalyst. The key design factor when operating a methanol plants is being able to control the heat relinquished from the exothermic reactions. This is attained in several ways by means of putting the catalyst in tubes encircled by water and cooling with feed in a multiple-bed reactor. As a result the crude methanol is refined through distillation. 4.2 Claus Sulfur Recovery Scott (1995) is of the opinion that Claus plants are the main route of recovering sulfur from natural and refinery gases. The process entails the removal of the acid gas (carbon dioxide and Hydrogen sulfide) with an amine procedure and then moving the resulting acid gas from the amine stripper into a furnace. In the furnace, about 30% of the Hydrogen sulfide is changed to sulfur dioxide. These two compounds react to form sulfur, with more or less 70% of the sulfur recovered in a condenser succeeding the furnace. Several phases of catalyst beds with intermediate reheating occur downstream of the Claus furnace to retrieve any additional sulfur. Elemental sulfur is generated when in each phase 2 moles of Hydrogen sulfide react with one mole of sulfur dioxide. Approximately 97% of the feed sulfur can be recovered in this manner (Scott, 1995). 4.3 Ammonia Production Partial oxidation of oil residues and steam reforming of natural gas forms the main source of hydrogen. Nitrogen is brought in as compressed air into the minor reformer. A reaction between Hydrogen and Nitrogen at high temperatures of between 750-1200º and pressures of 1500 to 3000 psig takes place. The process is accelerated by iron oxide with potassium hydroxide as the promoter. 4.4 Cryogenic Oxygen Plants In cryogenic process, air is filtered then compressed and cooled by the primary air compressor and is moved to the absorbers, where elements like hydrocarbons, water and carbon dioxide are gotten rid of from the air stream. The clean dry air moved to a series of heat exchange and distillation phases to separate the main components namely; argon, oxygen and nitrogen. 4.5 Fluid Catalytic Cracking (FCC) Is a technology developed in 1930s to 1940s as a result of increased demand for fuel in World War II. This technology process produces lighter extremely valuable products (mostly aviation fuel) from gas oil and refinery heavier streams through high temperature catalytic cracking. The main products from this technology include; propylene, coke, Dry gas and gasoline. The FCC process makes use of very fine particles of about 70 microns in measurement as a catalyst. These particles exhibit liquid properties when aerated with a vapour. The continuous pumping of the liquid catalyst transfers heat between the reactor and regenerator. The cracking reaction occurs as a result of combustion of coke in the regenerator hence heating the feed. 4.6 Natural gas reforming Steam Methane Reforming (SMR) technology This process encompasses conversion of natural gas feedstock to a mixture of gas referred to as synthesis gas comprising of carbon monoxide, carbon dioxide, and Hydrogen with steam as a reactant. This gas mixture also contains some traces of unreacted methane and steam. This process forms the basic step for much of the known industrial processes that include ammonia synthesis and the production of both hydrogen and methanol. According to Mokhatab and Poe (2012), the most cost effective method for production of hydrogen involves steam methane reforming and has a wide range of capacity for feed gas. The feed gas capacity ranges from 1 MMSCFD to 400 MMSCFD of methane feed for fuel cells and methane feed for ammonia production respectively (Mokhatab and Poe, 2012). The catalytic reactions of methane and steam produce the synthesis gas which is further purified through water gas shift reaction that increases the hydrogen components and reduce the carbon monoxide content. Ultimately, a final step purifies the gas by extracting all other components to give the final product hydrogen. 4.7 KBR SCORE (Selective Cracking Optimum Recovery) -Ethylene technology The main technique for the production of ethylene is thermal cracking of hydrocarbons where the gaseous hydrocarbons are momentarily heated to 1500-2000ºF. The process causes a free radical reaction, which breaks down the heavier saturated hydrocarbon chains into unsaturated smaller ones. The end product for this method is a mixture of gases such as butadiene, benzene, ethylene, propylene, and therefore need comprehensive purification and separations phases. 4.8 The Controlled Free Zone (CFZ) technologies The CFZ is a breakthrough technology that entails single-step process for separating acid gases from methane. It is an efficient process that gets rid of impurities from natural gas. It is suited for gas resources having huge amounts of carbon dioxide (CO2). This technology is less expensive in comparison with other technologies. It requires few processing steps and equipment hence ideal for offshore and remote applications. The CFZ technology has some benefits as follows: It entails a single step processing Conforms to natural gas pipeline quality prerequisites without extra polishing Needs no dehydration, solvent regeneration or additive recovery facilities No limit on CO2 or H2S content Deals with highly sour gases with ease Easily accommodates increases in feed concentration of sour gas constituents over the life of the facility Its economic merits supersede those of competing technologies as it expands with greater acid gas content High pressure operation Eliminates acid gas in high pressure and non-corrosive liquid form that can be delivered forth for use in enhanced oil recovery Reduces compression horsepower and equipment needs for enhanced oil recovery  Alternative to sulphur recovery plants Eliminate Hydrogen sulphide and other sulphur compositions with the carbon dioxide for disposal Gives a better option to high operating cost and development of expensive sulphur plants Overall cost savings Simplifies processes and reduces the number of equipment needed. Decreases fuel gas consumption, enabling greater gas sales revenue 5.0 Conclusion The number of phases and the procedures used in the process of producing pipeline-quality natural gas primarily depends upon the gas source and makeup of the wellhead creation stream. In some cases, the phases may be incorporated into one operation unit, carried out in a different sequence or at different plant location, or not may totally not be required. The several phases of gas processing begin at the wellhead. Nearly all natural gas creation contains hydrocarbon molecules in varying degrees of two to eight carbons which exist in a gaseous form at underground pressures. The molecules condense atmospheric pressure and collectively referred to as natural gas liquids (NGLs). Ethane propane and butane are the by-products most often related to NGLs recovery process among several other products extracted from gas processing facilities. Works cited 1) Busby, R. (2003). International petroleum encyclopedia. Tulsa, Okla.: Pennwell Corp. 2) Jones, D. and Pujado, P. (2006). Handbook of petroleum processing. Dordrecht: Springer. 3) Kelly I. (2006). Equipment Design and Cost Estimation for Small Modular Biomass Systems, Synthesis Gas Cleanup, and Oxygen Separation Equipment. Subcontract Report. [Online].Available from: http://www.nrel.gov/docs/fy06osti/39945.pdf [Accessed 18/04/2015] 4) Linde Process Plants, Inc. 2014. Natural Gas Liquids Recovery, CRYO-PLUS technology. Brochure. [Online].Available from: http://www.lppusa.com/international/web/le/us/likeleuslbpp30.nsf/repositorybyalias/lpp_natgas_broch/$file/2013 NGL CRYO-PLUS Brochure.pdf [Accessed 16/04/2015] 5) Mokhatab, S. and Poe, W. (2012). Handbook of natural gas transmission and processing. Waltham [Mass.]: Gulf Professional Pub. 6) Plunkett, J. (2008). Plunketts energy industry almanac 2009. Houston, Tex.: Plunkett Research. 7) Scott, K. (1995). Handbook of industrial membranes. Oxford: Elsevier Advanced Technology. Read More