SPE 167355

Improving Overall Performance and Reducing Energy Usage in Refinery Amine Units with Minimal CAPEX Badar Al Saadi , Michelle Valenzuela, Jim Hill, Eldon Baumeister; Dow Oil and Gas Business Unit of The Dow Chemical Company Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Kuwait Oil and Gas Show and Conference held in Mishref, Kuwait, 7-10 October 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract This paper will discuss the use of simulation techniques, key performance indicators, ideal solvent selection, routine solvent analysis for optimal hygiene, and system performance to increase acid gas removal capacity while maintaining environmental compliance. Additionally, the paper will share real field experience and learnings from the implementation of these practices. Introduction Due to the rapid increase in global oil demand, pressure for greater production with fields containing heavier (higher density/more carbon rich) and more sour (high in sulfur) crude has increased. The average quality of crude oil (i.e. medium gravity, sour crude) dominates the oil production from the Middle East. For example, Saudi Arabia’s response to the demand is the 900,000 barrel per day (bpd) mega project that will process heavy oil from the Manifa Field. The Field will support Saudi Arabia's plan to raise production capacity beyond the 12.5 million bpd from just above 11 million bpd today. With the trend towards heavier and higher sulfur containing crudes, refineries are increasing processing capabilities which can include capital-intensive projects and additional energy consumption. Furthermore, in order to meet stringent regulations for ultralow sulfur fuels in the global market, refineries must increase processing capabilities to accommodate a heavier, sour crude slate. This includes upgrading hydro treating capacity to address the additional sulfur load and adding acid gas removal systems to treat the resulting H2S. Often refineries design and operate acid gas removal systems with the sole objective of meeting permitted sulfur emission limits. MEA (monoethanolamine) and DEA (diethanolamine) are amine solvents commonly used for removal of H2S from sour gas streams. Refineries maintain low solvent concentrations to reduce degradation products and corrosion potential. Less amine in the system requires increased circulation rates and more aggressive stripping of the lean amine to meet stringent H2S and SO2 regulations. These practices result in excessive energy consumption and limited capacity. Capacity upgrades have become a challenge for refineries already struggling with tightening margins. Thus, solutions to boost capacity should focus on minimal capital expenditures. Specific to gas treating systems, there are two ways to increase the treatment capacity and optimize energy consumption. Both require minimal capital investment. The first method involves upgrading the chemistry of the solvent to increase capacity and reduce required processing energy (i.e. reboiler duties). The second method requires an understanding of the system performance. With the use of mass and energy balances, a plan is developed to optimize appropriate operating conditions and key performance indicators to increase the treating capacity, while maintaining environmental performance. This paper will discuss these two approaches in more detail, including the use of Dow proprietary simulators to determine optimum process conditions and the importance of continuous monitoring of process and solvent conditions. The paper will also share real field experience and learnings from actual implementation of these practices.

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Production of Heavy and Sour Crude Oil Heavy crude oil has been defined as any liquid petroleum with an API gravity less than 25.7. Oil containing more than 0.5 weight percent (wt %) sulfur is defined to be ”sour”. Only 20% of global oil production supply can be classified as light and sweet, with the remaining 80% classified as medium/heavy and sour. Particularly for the Middle East region, the global crude oil grades show that the majority of oil is intermediate and sour. The U.S. Geological Survey estimates that there are about 971 billion barrels of heavy oil in the Middle East region. All the countries in the Middle East will need to produce the heavy oil to offset the high demand on the oil globally. Investments in heavy oil have been accompanied by refinery expansion projects to process heavy hydrocarbon blends. This upgrade requires additional coking, vacuum distillation capacities and hydro treating processing units. Examples of such projects include the following:

• The SINOPEC Saudi Aramco JV Yanbu refinery project to process heavy oil from Manifa Field • The Kuwait Clean Fuels Project to upgrade the Mina Abdullah and Mina Al Ahmadi refineries and boost their

combined daily capacity to 800,000 bpd of clean fuel • The Saudi Aramco Shell Refinery Co. (SASREF) project that commissioned an ultra-low sulfur diesel unit in

March, 2010 to produce about 100,000 bpd of diesel fuel while meeting a sulfur content requirement of less than 10 parts per million (ppm)

• A $7 billion expansion project for Motiva Port Arthur, US refinery to add 325,000bpd to process Canadian heavy oil crude with the addition of a 100,000bpd coker

• A $3.8 billion expansion project for BP Whiting, US refinery to increase the refinery capacity by 260,000bpd to refine heavy oil

Opportunities for Energy Management Refineries must also consider ultra-low sulfur diesel (ULSD) requirements and environmental regulations when considering upgrading refinery assets to treat heavier crudes. Additional hydro treating capability to remove more sulfur, especially from sour crudes, will result in more sulfur containing waste or “acid” gases. Further processing of the acid gases is required before final disposition: emission, incineration, combustion, etc. Typically, refineries use amine-treating systems to process waste gases in refineries. As with the other processing systems in the refinery, amine systems can require a significant amount of energy depending on asset age and condition, acid gas loads, solvent used, and operating parameters. This paper will also highlight energy reduction techniques for amine systems that use products, technologies, and services in the Dow AMINE MANAGEMENTSM Program. Refinery Amine Systems Refinery amine systems are required to effectively remove acid gases from a variety of gas and/or liquid streams to targeted levels. Most refineries use amine treating systems (Figure 1) consisting of the following equipment:

• Absorber: used to “scrub” or remove acid gases from the inlet stream with an amine solvent • Rich amine flash tank: used to separate co-absorbed components (i.e. hydrocarbons) from the rich amine • Lean/Rich Cross Exchanger: used to heat the rich amine solvent by exchange with the hot lean amine from the

regenerator • Regenerator (including reboiler): used to steam strip the amine to remove acid gases before recycling to absorber as

lean amine • Condenser: used to cool the acid gas stripped from the rich amine; condensed water returns to top of regenerator • Amine cooler: used to cool the lean amine before entering the absorber

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Figure 1: Typical Refinery Amine System

Solvent Selection The development of amine solvents for acid gas treating has evolved from traditional generic amines, monoethanolamine (MEA), diethanolamine (DEA), and diglycolamine (DGA), to more selective gas treating amines that include diisopropanolamine (DIPA) and methyldiethanolamine (MDEA). The increased selectivity of the amine allows for preferential H2S removal and CO2 “slipping” into the treated gas stream, which is especially important for improved sulfur plant operations. MDEA, a tertiary amine, eventually became the most common selective solvent due to its resistance to degradation, low tendency for corrosion, higher acid gas loading capacity, and lower energy consumption. The latest advances in amine technology have included the introduction of formulated specialty solvents developed to overcome the weaknesses inherent with generic amines. Proprietary additives are combined with the amine, offering the greatest potential for system optimization. Initially, formulated solvents were based on MDEA to provide increased H2S selectivity and energy savings. However, additional formulations and products have been developed to provide enhanced performance benefits in specific refinery applications. Performance solvents, for example, are now available to achieve the following objectives:

• Treat acid gas to meet <10ppm H2S specifications in low pressure (i.e. tail gas units) applications while minimizing steam usage

• Reduce solvent losses in LPG service • Reduce corrosion rates while increasing capacity • Reduce energy consumption and, in turn, CO2 emissions from utility generation

Table 1 below compares the overall performance of the gas treating solvents.

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Table 1: Typical Amine Solvents Used in Refinery Acid Gas Treating Systems

MEA concentration is limited to 15 to 20 wt% due to its degradation characteristics. DEA is a secondary amine, and its operating concentration is limited to 30 wt%. MDEA based solvents can operate at much higher concentrations with low corrosion potential. Substantial additional treating capacity is available with the formulated solvents by increasing the operating concentrations to well above 40 wt%. Furthermore, formulated solvents can tolerate higher acid gas loading. The energy savings realized with formulated solvents stem from a reduction in sensible heat, a lower heat of reaction, and a reduction in necessary stripping steam. Tertiary amine-based solvents can operate at higher concentrations without increased concern for corrosion. Therefore, circulation rates can be decreased, and the sensible heat requirement in the regenerator reboiler is reduced. The heat of reaction for the formulated solvents and tertiary amine is lower than primary and secondary amines. This reduces the amount of energy required to regenerate the solvent. It should also be noted, as shown in Table 1 above, that as the chemistry upgrades from MEA to formulated solvents, the resulting benefits in order of impact from greatest to least are as follows: increased capacity and acid gas selectivity, reduced corrosion and energy consumption, and improved operating stability. Identifying the optimal solvent is critical when increasing the capacity and reducing energy consumption. Many factors should be considered to ensure compliance with environmental requirements as well. Nevertheless, even with the best solvent selection, optimal operation of the amine unit is equally important. To maximize the performance potential of the gas treating solvent, the amine unit should be optimized. Amine System Performance and Management A proactive approach to managing amine systems is required to provide both economic and performance benefits. The Dow AMINE MANAGEMENTSM Program is a comprehensive service program developed to provide sustainable results that reduce overall costs for amine treating systems while meeting rapidly changing demands of refinery unit operations. As part of the program, an initial survey of the refinery amine system(s) is performed to gather key operating data (e.g. flows, temperatures, etc.) as well as equipment data (e.g. absorber and regenerator design data, reboiler duties, etc.). Amine samples are also collected and analyzed. The information collected is used to develop a fundamental understanding of current performance and identify opportunities for improvements. For instance, high rich loading (based on the amine analysis) and difficulty to meet H2S or CO2 specification (based on the operating data collection) could indicate maximum loading of the solvent. This can be remedied by optimizing the circulation rate to meet the treatment requirements and environmental regulations.

Increasing Energy Savings Amine

Acid Gas Selectivity

Increasing Treating Capacity

Formulated Solvent

Very high H2S Removal

MDEA High H2S Removal

DIPA Some H2S Removal

DGATotal Acid Gas

Removal

DEATotal Acid Gas

Removal

MEATotal Acid Gas

Removal

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To complete the amine unit evaluation, technical tools are used to outline an improvement plan to meet refinery objectives. These tools include Dow proprietary simulation platforms, routine analytical analysis, pilot plant capabilities, heat stable amine salt management, and extensive knowledge and experience with over 800 global customers. An improvement plan is presented to the refinery, implemented, validated, and sustained through routine visits and system reviews with Dow Engineers. The Use of Simulation Tools Dow proprietary simulation platforms are used to develop operational solutions to meet energy reduction and/or other targets. State of the art simulation tools provide design and operating information to help achieve the following:

• Optimization of amine flow requirements and treatment results • Gas treating solvent selection (including formulated solvents) • Exploration of process limitations • Process Flow Diagram • Material balance with stream data tables • Exchanger duties and other design information

The simulation output provides details on the current system performance, expected benefits by optimizing performance, and any limitations of the amine system. An example of a temperature profile output is shown in Figure 2. Under ideal liquid amine-to-sour gas (L/G) ratios, the temperature profile of the absorber tower is shown with the “temperature bulge”, or exotherm, at the bottom of the tower. However, in an effort to aggressively increase gas rate and treating capacity, it is possible to change the liquid-to-gas ratio such that the temperature bulge shifts to the middle or top of the absorber tower. This can compromise the treating capability and H2S removal of the absorber system. When optimizing systems to increase capacity or reduce energy usage, it is important to understand the limits of the process. An upset in the amine unit affecting a downstream unit or causing process downtime can quickly minimize the value of a poorly implemented optimization plan.

Figure 2: Amine Absorber Temperature Profile with Normal L/G

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Liquid Temp (F)

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The Use of Pilot Plant Capabilities In conjunction with the use of simulation tools, pilot-plant results are beneficial in modeling simulation output or plant performance, developing customer specific formulations, and validating operational improvements. As part of the AMINE MANAGEMENTSM Program, pilot plant capabilities have helped:

• Demonstrate lower energy and CO2 removal with solvent conversion • Quantify organic sulfur removal performance for new gas treating applications • Validate CO2 slip and improve H2S removal in low pressure applications (i.e. Tail Gas Units) • Screen new additives and formulations for better acid gas removal with less energy usage

Solvent Hygiene Often, energy management programs focus on equipment or process optimization. However, specific to amine systems, routine solvent analysis is important in identifying opportunities for capacity gains and energy savings. Monitoring amine solvent health is required to maintain optimal system reliability and operational performance. Ideally, routine sample analysis should include identification and quantification of all the components in the solvent. This would include amine concentration, acid gas content, individual degradation components, specific contaminants, and water content. Contaminants in the system, such as formate, thiosulfate, thiocyanate, and other organic and inorganic acids, bind the amine to form Heat Stable Amine Salts (HSAS), which reduce functionality. High HSAS levels reduce system capacity, which can require increased steam usage and/or higher amine circulation rate to maintain system performance. High HSAS can also contribute to increased corrosion in the gas treating system. Thus, it is important to monitor and maintain low levels of HSAS in the system. Acid Gas loadings in the lean amine can serve as an indicator of stripping performance. In refinery systems, H2S is present and measured as acid gas loading in the amine solvent. The absence of H2S in the lean amine sample could indicate the amine is over-stripped. Operating data would then be used to confirm regenerator conditions and steam rates could be reduced. As part of the AMINE MANAGEMENTSM Program, a routine solvent analysis program is developed to monitor and trend solvent health as a means of determining system performance, anticipating and/or troubleshooting problems, and identifying opportunities for system improvement. Case Studies The following case studies will show how the implementation of the AMINE MANAGEMENT Program led to significant cost savings for each refinery. In all cases, solvent selection coupled with an optimization plan led to better treating performance and reduced steam consumption. The refineries below continue to use the Dow AMINE MANAGEMENT Program to proactively identify opportunities for optimization and improved operational performance. Case Study #1 A large-size, U.S. refinery completed a capacity expansion project to increase heavy crude processing capability. The expansion was successful but added strain on the utilities and downstream assets increasing energy costs and limiting amine treating capacity. The shift in the crude slate increased the sulfur content and resulting acid gas volumes. Although the refinery was equipped with a complex amine treating system consisting of three regenerator trains and 18 gas and liquid contactors, the current solvent and system conditions were unable to maintain reliable acid gas removal from the process streams. A comprehensive, on-site evaluation of the refinery operations was conducted using the AMINE MANAGEMENTSM Program and included detailed simulations of the existing amine systems with a comprehensive review of maintenance and operating procedures. The assessment showed that the refinery could achieve the following objectives:

• Address increased acid gas volumes without additional capital expenditure • Decrease operating costs by reducing energy use • Increase system reliability by reducing corrosion

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The AMINE MANAGEMENT Proposal recommended a solvent upgrade from the current solvent, DEA, to a high capacity, UCARSOL™ solvent formulated for primary amine treating systems in refineries. Recommended operating concentration for DEA is less than 30% due to degradation that increases corrosion. However, the UCARSOL specialty solvent can target a much higher operating concentration, increasing the capacity available to remove acid gas. With the upgrade to the UCARSOL product, the refinery increased solvent concentration to an optimal target allowing for reduced circulation rates and steam usage with the added benefit of reduced corrosion potential. In addition to the solvent upgrade, process and solvent conditions were optimized to improve system reliability and maintain environmental compliance. Amine loading targets and steam-to-lean amine (lb/gal) ratios were established to prevent over-stripping. The steam-to-lean ratio is a quick means of determining the amount of steam used to regenerate, or strip, the amine and should not be used as a replacement for reflux ratio. Steam-to-lean ratios were reduced by as much as 20% resulting in less steam usage. The lean loadings were set at 0.01-0.015 m/m (mol acid gas/mol amine) and rich amine loadings were increased to target greater than 0.4 m/m allowing for reduced reboiler duty or increased treating capacity. When optimizing the system, targets and/or limits should account for occasional process swings (i.e. increase in H2S content in inlet gas, increasing gas content, equipment fouling, etc). One of the regeneration systems at the refinery was able to achieve a very aggressive steam-to-lean ratio (greater than 25% reduction) without impacting treating performance at current conditions. However, the system target was set to achieve 20% reduction to ensure safe operation and avoid H2S and SO2 exceedances. (i.e. Sulfur Recovery Unit processing). The overall steam usage by the amine system regenerators is shown over a 4-year period (2002-2006) in Figure 3. Energy and cost savings including the upgrade to the UCARSOL™ specialty solvent resulted in significant energy savings – 175,000 MMBtu/y. Total energy usage was reduced by nine percent and better utilization of the new solvent helped reduce amine losses by 17 percent. In addition, utilizing the AMINE MANAGEMENTSM Program extended the performance of the existing amine system by increasing acid gas removal capacity, avoiding capital investment and optimizing overall operating costs.

Figure 3: Steam Usage for Refinery Amine Regenerators

Case Study #2 This case study will show how a systematic approach using the Dow AMINE MANAGEMENT Program was able to address the refinery needs. Initially, refinery objectives were focused on identifying a new solvent to enhance processing flexibility. However, through the years, opportunities to reduce solvent losses, enhance treating performance, and reduce energy usage have resulted in over 350,000 MMBTU/y savings, which, conversely, could translate to increased capacity. A mid-size refinery in the U.S. used two generic solvents to treat process gas in the main and tail gas units. However, to increase system reliability and flexibility, the refinery moved to an integrated amine treating system requiring only one solvent for both primary and tail gas systems. The solvent would be required to meet treating needs for the contactors on the main system, including LPG liquid treaters, as well as provide CO2 slipping and H2S selectivity for the tail gas application.

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A comprehensive evaluation of the system was conducted using the AMINE MANAGEMENTSM Program to meet the following refinery objectives:

• Provide a single amine solvent to be used refinery wide • Provide enhanced total sulfur removal • Maintain adequate CO2 slip while removing meeting H2S removal targets

A new specialty solvent was developed to meet the refinery needs. The refinery upgraded to a UCARSOL™ solvent formulated for both primary and tail gas applications. Hesitant to increase solvent strength, the refinery operated at less than 30 wt% to minimize losses. However, with tools from the AMINE MANAGEMENT Program, losses were tracked to reduce overall losses by 34% (as shown in Figure 4).

Figure 4: Refinery Amine Loss Reduction

With losses optimized, another comprehensive evaluation by Dow engineers was performed and showed that increasing solvent concentration to greater than 40wt% would result in a 26% decrease in energy costs, totaling a net savings of over $1MM/year. Conversely, if energy usage was not a key objective, the concentration upgrade would increase overall treating capacity of the amine system by over 30%. Additional recommendations included reducing the steam-to-lean ratio and adding improved process control logic to maintain optimal circulation rates. The refinery increased the amine strength to 35wt% and implemented the optimization recommendations, which resulted in a reduced amine circulation rate. The lower rate led to a 30% decrease in regenerator duty (shown in Figure 5). The overall energy reduction was approximately 40 MMBTU/h. These improvements translate to 350,000 MMBTU/y energy savings or overall potential treating capacity increase of approximately 30%.

Figure 5: Refinery Trend in Total Regenerator Reboiler Duty

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Case Study #3 With the flexibility to process large volumes of heavy crude, a large, U.S. refinery needed to achieve the following objectives:

• increase gas treating capacity • improve system reliability • reduce total operating costs to become more competitive

The existing amine treating system used MEA. Although MEA is aggressive in total acid gas removal, the primary amine readily degrades which increases the corrosion potential of the solvent. To minimize corrosion, the amine requires frequent and costly reclamation to remove degradation by-products. Operating concentrations are limited to 20wt% and regeneration for MEA requires more stripping steam due to a higher heat of reaction as compared to formulated solvents. The use of MEA limited long-term capacity and total cost reduction goals for the refinery. An evaluation of the amine system was performed using the AMINE MANAGEMENTSM Program. The evaluation determined that a solvent upgrade and optimization would help the refinery increase treating capacity by 48%, reduce amine losses by 50%, and reduce energy consumption by approximately 500,000 MMBTU/y. A two-step approach was developed and implemented to help the refinery achieve outlined objectives. Phase 1: Solvent Upgrade The refinery upgraded from MEA to a UCARSOL™ solvent designed to minimize energy usage and meet acid gas removal requirements in refinery applications. With the formulated solvent, the operating concentration was increased to an optimal range and steam-to-lean ratios were reduced by 20%. Phase 1 of the optimization plan resulted in an immediate circulation rate reduction and an energy savings of over 400,000 MMBTU/y. Furthermore, the upgrade to the UCARSOL solvent occurred with no shutdown or incidents. A routine analytical plan was implemented to ensure optimal solvent and system performance. Solvent losses were also tracked, monitored and improved. Overall, solvent health improved, solvent losses were reduced by 59%, and corrosion decreased. Phase 2: Optimization The next step was to focus on optimization of the amine treating system. The individual gas contactors were evaluated using simulation techniques from the AMINE MANAGEMENTSM Program. Proprietary equations were developed and implemented to optimize circulation rates and rich loadings were increased to target an optimal range. This resulted in an additional 15% reduction in circulation rates and 300,000 MMBTU/y in energy savings. The two-phase approach led to 700,000 MMBTU/y energy savings, a 59% decrease in solvent losses, and improved system performance with a total cost savings of over $3MM/year. Case Study #4 Another example of a mid-size refinery shows how using the Dow AMINE MANAGEMENT Program was able to address the refinery needs. The refinery objectives were to:

• Reduce amine losses without impacting CO2 slip, MDEA was utilized • Reduce corrosion issues • Enhance the treating performance

Although MDEA provides preferential H2S removal and CO2 “slipping” into the treated gas stream with operating concentrations up to 50 wt%, the solubility of MDEA is high in LPG. Therefore, to minimize MDEA losses, the refinery operated at a less than optimal concentration. A new UCARSOL™ solvent was developed to meet the refinery objectives. With the upgrade to the performance solvent, the refinery reduced amine losses by 40% as shown in Figure 6. The conversion was successfully completed without plant shutdown. The solvent upgrade will also allow for increased treating capacity if needed in the future by targeting higher solvent concentration.

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Figure 6: Refinery Amine Loss Reduction

As part of the AMINE MANAGEMENTSM Program, a routine solvent analysis program was developed to monitor and trend solvent health and manage corrosive HSAS levels (Figure 7). Reducing and managing the mechanism for corrosion (i.e. HSAS, contaminants, degradation components) with frequent sample analysis and proactive HSAS management, resulted in a decrease in system corrosion. Additionally, the service life of the filters improved dramatically with reduced system particles from corrosion.

Figure 7: HSAS Management

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Summary As crude slates shift towards heavier, sour crudes, it is necessary to consider cost-efficient means of increasing processing flexibility while heeding environmental regulatory requirements. Specific to acid gas removal systems, this paper reviewed the implementation of AMINE MANAGEMENTSM Program tools and techniques to increase the treating capacity and reduce energy consumption resulting in a reduction in total operating costs. In the case studies discussed, upgrading from generic solvents to formulated solvents improved overall system performance and increased gas treating capacity while meeting refinery objectives to address process expansion and flexibility needs. With the use of proprietary simulation tools, ideal solvents were selected for the individual refineries and solvent upgrades were safely implemented with no environmental exceedances. Operating limitations were identified and targets for optimization were set specific to acid gas loadings and stripping steam ratios. In addition, routine analytical plans were established to monitor solvent performance and proactively address system issues.

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References Ackman, R, Pirtle, L. “Amine Treating: A Review of the Technology”. AICHE Spring National Meeting, April 2012

“Annual Energy Outlook 2011”. Available at http://www.eia.gov/oiaf/aeo/tablebrowser /. February 12, 2012. “Carriage of Heavy Crude Oil”. Available at www.mcqservices.com. February 12, 2012. “Clean Fuel Project CFP”. Available at www.knpc.com/en/Projects/Pages/default.aspx. March 6, 2012 “Consequences of a Heavier and Sourer Barrel” Petroleum Review, April 2007, pages 30-32. Echt, W, Wendt, C. “Reduce Sulfur Emissions From Claus Sulfur Recovery Unit Tail Gas Treaters”. AICHE Spring National Meeting, March 1993. “Energy Consumption”. Available at www.need.org/needpdf/infobook_activities/IntInfo. February 12, 2012. “Energy Efficiency Roadmap for Petroleum Refiners of California”. California Energy Commission. Prepared by Energetics Incorporated. April 2004. “Facing Up to End of 'Easy Oil'. Available at http://online.wsj.com . February 14, 2012. GPSA Engineering Data Book, Eleventh Edition (1998). Gas Processors Suppliers Association International Energy Agency (IEA) report Refinery Oil and Gas Market 2010. Kohl, A, Nielson, R. “Gas Purification” (5th ed. Houston: Gulf Publishing Company, 1997.), p205 “Refining and Chemicals”. Available at http://www.saudiaramco.com/en/home/our operations/refining--- chemicals.html. February 14, 2012.