by Guangdong Qu

After dropping to a staggering 7.4% GDP in the third quarter of 2012, China’s economy is showing signs of promising activity on a steady path to recovery. Despite the challenging economic situation, China’s PMI has remained above 50 for five consecutive months, indicating an increase in manufacturing activity as well as a rebuilding economy.

According to forecasters, auto production is leading the way in China’s growing manufacturing activity and is expected to continue to grow at a rate of 7% in the next ten years. By 2020, total auto production is expected to double, and with it, the demand for oil products, plastics and rubber.

Given the expected increased demand for transportation fuels, China’s refining industry faces significant challenges with limited domestic resources, causing an increased dependence on international crude oil. By 2020, two-thirds of crude demand in China will be fed by imports, as Chinese oil production is projected to remain flat at about 200-220 MMT for the next 10 years.

While crude oil production remains even, capacity and throughput is expected to grow at a rate of 4-5% over the next ten years, and the increased demand for oil products will drive additional capacity of 260 million tons by 2020. Hydro-processing units will be added to meet quality requirements, and China will implement Euro V specifications for the entire country starting in 2017. Efforts to ensure cleaner air will require modifications to existing assests, as well as the need for new facilities. Future trends in China’s refining industry indicate an increase in large-scale, hydrogenation, oil-coal-gas co-processing and transport fuel yield maximization.

UOP China has over 50 employees in Beijing and Shanghai. Technical experts as well as local sales, services and support staff all ready to help meet China’s growing demand at global specifications.

China’s economic outlook will continue to gain strength because of its improving domestic conditions. The Chinese 18th CPC Congress and the 12th National People’s Congress (NPC) have successfully realized the shift of Chinese leadership and have decided to attach greater significance to improving the quality of economic development by pursuing a healthier growth pattern, instead of focusing just on the expansion of GDP. The new Chinese leadership plans to use urbanization to help transform the economic model from export-oriented growth to domestic consumption-driven development. The growth of China’s domestic consumption will contribute greatly to the growth of GDP.

by Lee Hermitage

Russia is without question an oil and gas nation. It was the world leader in crude oil production in 2012, producing almost 10 billion barrels (1.37 billion metric tons) and beating Saudi Arabia into second place. It also has the world’s largest natural gas reserves at nearly 1,700 trillion cubic feet (48,100 billion cubic metres). Both oil and gas production are growing at more than 1% annually and, with GDP growth averaging 3.5 to 4%, Russia is seen by many as a land of opportunity.

Upgrading of the refining industry
The Russian car fleet is forecast to grow at 4.1% over the next 5 years with annual new car sales reaching 4 million by 2017. Older, traditional cars are increasingly being replaced with newer models including foreign brands. The Russian market is being increasingly targeted by foreign car manufacturers with many including Volkswagen, Ford and BMW, having production facilities in Russia. These changes are driving transport fuels demand and, in particular, growth in higher quality gasoline and diesel. The Russian Government has also recently mandated the introduction of Euro V quality fuels in 2015. This is leading to wide scale upgrade of refineries to meet domestic demand and to allow refiners to capitalize on profitable exports of Ultra Low Sulfur Diesel to Europe. In parallel, the Russian Government introduced changes to export duties, the so called “60/66” regime. This, together with reductions in sulfur content for marine fuel use, has significantly reduced the attractiveness of the fuel oil export market. Many refiners rely heavily on fuel oil exports and these changes are driving them to introduce upgrade technologies to improve the quality of their fuel oil or convert to more profitable products. Equally, some refiners are looking to broaden the spectrum of products produced at their plants by integrating petrochemicals production.

Expanding natural gas infrastructure
With gas demand relatively flat, Russia is looking to export opportunities for its natural gas. Most gas is currently exported to Europe by pipeline and there is continued investment in the pipeline infrastructure to support this. Russia is also, however, seeking to become a stronger payer in the LNG market, particularly in exports to Asia. Russia’s first LNG production facility was constructed on the Sakhalin II facility in 2009 with further projects planned, including a $20 billion project on the Yamal Peninsular. Gas producers are also seeking new ways to monetize their gas streams through innovative technologies. These include the Methanol-to-Olefins (MTO) process which allows them to produce higher value fuels and petrochemical feedstock. A further development in Russia is the introduction of a 5% limit on the flaring of Associated Petroleum Gas (APG) produced during crude production. Russia currently produces 60 billion cubic meters of APG each year and 30% was flared in 2012. Oil companies need to invest in technologies to utilize this additional volume or face heavy fines. These flaring reductions are also leading to greater capture and usage of Natural Gas Liquids (NGL). In addition to the export potential for these products, they are used as petrochemical feedstock with the SIBUR plant in West Siberia providing the largest infrastructure for processing APG and NGL in Russia.

Building new petrochemical clusters
Russia also has ambitious plans for its petrochemicals industry. Despite increasingly strong demand for plastics and polymers, the industry remains focused on producing petrochemical raw materials such as naphtha, ethylene and propylene. Some of this production, particularly naphtha, is exported while many of the finished, polymer products are imported. The Russian Ministry of Energy has formulated a strategy for the expansion of the industry by the creation of six petrochemical clusters across the country. When these plans come to fruition, polymer and plastics production is expected to grow up to 6 times. Good availability of feedstock at attractive prices, increasing domestic demand for polymers and good export opportunities will create a compelling argument for these projects. This will also drive continued investment in the production of ethylene, propylene and aromatic feedstocks over the next 10 years. Several projects are already underway, for example ethylene expansions at the Gazprom Neftekhim Salavat and Nizhnekamskneftekhim.

Recognizing the incredible potential of this market, UOP has steadily expanded its presence in the region with our Moscow Office growing its Sales, Technical Support and Services staff. With its local presence, this team is dedicated to providing customers in Russia and the wider CIS market with the high quality service they expect and deserve.

by Eric Baker, Jessy Trucko and Woo Kyung Kim (SK Innovation, Incheon South Korea)

The recent boom in gas field production from new technologies such as hydraulic fracturing has resulted in abundant production of natural gas. As natural gas exits the well head it decompresses, causing heavier hydrocarbons to condense out of the vapor phase as the temperature and pressure decrease. These condensed heavy hydrocarbons are recovered as liquids commonly referred to as natural gas condensates. Natural gas condensates cover a wide boiling point range from pentanes, through the light and heavy naphtha ranges, and to the heavier jet fuel and diesel ranges.

Although natural gas condensates fractionate into boiling point ranges that refiners are familiar with, they exhibit very different concentrations and species of mercaptan molecules. The mercaptans present in natural gas condensates are typically linear mercaptans. This, combined with high concentration levels, make these feeds challenging to treat. Two effective options exist for the refiner that would like to refine these lower cost condensates into kerosene or jet fuel – hydrotreating and mercaptan oxidation via sweetening (conversion of mercaptan to disulfide) technology. Although hydrotreating removes these mercaptans, it requires increased hydrogen supply and capacity in an existing hydrotreater or a large capital cost investment to realize. Alternatively, the UOP Merox™ Fixed Bed Sweetening Unit with Merox No. 10 catalyst technology requires low capital investment and minimum operating cost while producing on specification kerosene or jet fuel.

Treating unit comparison and challenges
SK Innovation in Incheon, South Korea produces jet fuel from two kerosene sweetening units receiving the same feed blend for the production of jet fuel. The smaller kerosene treater (#1 KMX) was designed by UOP and loaded with Merox No. 10 catalyst. #2 KMX is a non-UOP licensed unit, initially loaded with a non-UOP catalyst. SK historically processed a blend of various streams to make jet fuel, but began to produce off-specification jet fuel in #2 KMX when the mercaptan content increased, due to blending RasGas Condensate from the South Pars field (Qatar) in the feed. Unfortunately, SK could not make the desired jet fuel specification consistently with the treating technology and catalyst in #2 KMX. SK needed to process jet fuel through their hydrotreater #1 KGHT to blend its’ product with the jet fuel pool and ensure on specification by offsetting high mercaptan product from #2 KMX.

SK reloaded a high activity version of the non-UOP catalyst into #2 KMX in late 2009 in an attempt to achieve conversion equivalent to #1 KMX. SK had to reduce #2 KMX throughput to meet specification. Further addition of the Ras Gas condensate to the feed caused the catalyst performance in #2 KMX to deteriorate quickly and exceeded the maximum internal mercaptan sulfur specification of 20 wppm sulfur and the sales maximum of 30 wppm sulfur (see Table 1). Ultimately, SK switched to an easier to treat feed with less feed mercaptan until a better alternative could be found.

Table 1

SK continued to compare the performance of #1 KMX with Merox No. 10 catalyst against the catalyst in #2 KMX with the same feed. Over a two month period, SK observed higher levels of conversion across the Merox No. 10 catalyst despite the age of the Merox No. 10 catalyst in #1 KMX. The unique formulation of the Merox No. 10 catalyst increases activity over other treating catalysts (including UOP’s Merox No. 8 catalyst), while maintaining activity in difficult to treat environments by providing increased resistance to fouling by organic acids such as sodium phenolate and sodium naphthenate.

Merox No. 10™ reload and results
After further evaluation of the data, UOP and SK agreed that despite the differences in reactor vessel design, Merox No. 10 catalyst would be a beneficial replacement of the non-UOP catalyst in #2 KMX. They reloaded with Merox No. 10 catalyst as a drop-in replacement, without any need to revamp the unit.

SK loaded #2 KMX with Merox No. 10 catalyst and evaluated the performance of the new catalyst. During Performance Testing, SK processed a higher portion of RasGas condensate to #1 KMX and #2 KMX units, increasing the mercaptan load by over 250%. In addition, they were able to realize product mercaptan concentrations of less than 8 wppm sulfur with deceased air injection rates (Table 1).

Table 2

Merox No. 10 catalyst has been in service in the #2 KMX reactor since early 2011 with excellent performance. The catalyst change has allowed #2 KMX to process 72% more mercaptan sulfur while reducing off spec product by more than 50%.

In the original configuration, hydrotreated kerosene needed to be added to the jet fuel blend to reduce the amount of mercaptan sulfur in the jet fuel product. This is an expensive product to use for dilution of jet fuel. The new Merox No. 10 catalyst performance meets the specifications of mercaptan sulfur in jet fuel without the need for dilution with hydrotreated kerosene.

Conclusion
Merox No. 10 was able to significantly improve the profitability of the SK-Incheon refinery, by approximately 6 million USD/year. The activity and stability benefit of Merox No. 10 catalyst allowed SK to process a difficult-to-treat condensate in higher quantities and allowed them to off-load one of their hydrotreaters. The refinery is pleased with the operations of both Kerosene Sweetening units loaded with Merox No. 10 catalyst and has plans to increase treating capacity using UOP technology (new units and revamps). For more details about the economic benefits of Merox No. 10 catalyst, please visit www.UOP.com.

by Mohamed Shakur, Ka Lok and Richard Gaicki

UOP’s Chlorsorb™ System enables the refinery to eliminate the use of caustic and the disposal of caustic associated with the operation of the CCR in the UOP PlatformingTM unit. This can add up to $3.0 million USD of operating savings per year for a CCR Platforming unit processing a feed rate of 30,000 BPD. The savings are achieved from the significant reduction in chloride usage, the elimination of caustic usage and the associated treatment of spent caustic as well as reduction in overall utilities costs (see Table 1). Figure 1 shows the conventional vent gas caustic scrubbing system.

Table 1
Benefits of the Chlorsorb System Compared to a Caustic Scrubber System

Figure 1
Caustice Scrubber for Vent gas Treating

Chlorsorb System removes chlorides from the regeneration and reduction gases

There are two Chlorsorb System options as shown below.

1. Regeneration Vent Gas: The main use of the Chlorsorb System is for recycle of chloride from the regeneration zone vent gas (see Figure 2). In this process, the vent gas is contacted with spent catalyst at appropriate conditions to remove more than 97% of all chlorides from the vent gas. If higher chloride removal is needed, simple modifications are available which can achieve 99.9% chloride removal without the need for caustic scrubbing.
2. Reduction Zone Effluent Gas: In the second option, the chloride liberated during catalyst reduction is re-adsorbed on spent catalyst.

Figure 2
Chlorsorb System for Vent Gas Treating

When both options are used together, the Chlorsorb System can reduce organic chloride consumption by at least 70% and reduce consumption of chloride adsorbent for Platforming unit net products by 50%.

Broad customer acceptance and significant commercial experience
By 2012, after 14 years from its introduction, 100% of UOP customers for new design units chose the Chlorsorb System while a number of older CCR units are revamped with the Chlorsorb System. There are 38 Chlorsorb Systems in operation on UOP CCR units with another 45 units in design or construction. One large refining company has 6 operating chlorsorb systems with another 5 in construction. Several other refineries have 3 or more chlorosorb systems in operation or design.

Chlorsorb System can meet all environmental regulations including RMACT II in the USA
With its ability to remove more than 97% of chlorides, the Chlorsorb System is accepted by the US EPA (under RMACT II) as an approved solution for waste gas chloride management. The Chlorsorb System has demonstrated that it can meet between 1 and 30 ppmv of total Chlorides in the vent gas (see Table 2).

Table 2
Chlorsorb System has Demonstrated Better than 98% Chloride Removal in Commercial Units

Caustic Scrubbing concentrates dioxins in the spent caustic
It should be noted that when caustic scrubbing is used, the chloride compounds from the gas are neutralized while the dioxins are transferred to the liquid phase into the spent caustic. In some locations, the dioxins must be removed from the spent caustic. This is usually done by passing the spent caustic over activated carbon filter which concentrates the dioxins on the carbon. The dioxin-contaminated carbon is then shipped to a hazardous handling facility for incineration.

Customers benefit from simpler operation and reduced maintenance costs
With the Chlorsorb system, there is no liquid waste to treat and no hazardous waste removal and handling. Refiners benefit from reduced maintenance costs. The Chlorosrb system can be used for new units as well as revamps. Some refiners in the USA have added the RVG Chlorsorb system to comply with RMACT II requirements. Other refiners have added the Chlorsorb system to their CCR to eliminate the use of caustic and shut down their vent gas wash tower.

To learn more about the UOP Chlorsorb System, visit www.uop.com or talk to your local sales representative.

by Rebecca Liebert

Modularized gas processing equipment has been demonstrated as a proven solution to deliver fast and effective acid gas and contaminant removal as well as natural gas liquids (NGL) recovery within the North American Shale space. Through a packaged plant delivery model, modularized amines, adsorption, and cryogenic turboexpander equipment skids can be prefabricated and delivered to customer locations, including remote areas, which can be particularly advantageous for gas flow rates below 500mmscfd and scale able to higher flows by incorporating multiple equipment trains.

This article highlights decision framework to guide the appropriate selection of gas processing technologies. Within the presented framework, it is not only important to select the proper processing technology but also to consider the interactions among each gas process unit and to adjust sequencing of the process steps to optimize operations, thereby requiring operating flexibility within the overall gas processing system. Experience within the gas processing space has proven that flexibility should serve as a key attribute when selecting the proper solution for gas processing. Flexible operating and investment capabilities will become more important as many regions develop more sub quality and distributed gas reserves which are likely to increase the variability of the feed gas composition and feed flow rates.

Gas Processing technology decision guide
Numerous factors impacting the upstream resource, midstream project specifics, and downstream commitments affect the selection of gas processing technologies. The key decision blocks and variables underlying a design’s decision making matrix are displayed below in Figure 1.

Figure 1
Flow Scheme Representing Key Decision Criteria for Gas Processing Projects

The upstream factors impacting gas processing technology selection include:

• Hydrocarbon (HC) distribution composition of natural gas liquids and/or crude oil within the feed stream
• Production profile of the hydrocarbon reserve
• Feed gas contaminants including acid gas (CO₂, H₂S, Mercaptans), Mercury, Arsenic, and Nitrogen
• Feed gas pressure and flow rate
• Ambient conditions such as temperature
• Onshore/off-shore situation of resource and processing equipment
• Regional fiscal regime impacting project funding
• Environmental constraints, either local or global

When considering plant configurations and design decisions, operating flexibility should serve as a key design objective for the processing system. Flexibility is important due to the complex interrelationship and relative uncertainties among (i) input upstream factors, (ii) interactions among the processing plant functional blocks, and (iii) overall delivered project economics and/or downstream commitments.

Within the gas plant configuration, the dynamic interactions among functional blocks within Figure 1 will also drive processing systems towards more flexible operations.

When determining the proper solution set for a gas processing project, it is important to conduct the following three exercises:

1. Select the proper technology solution within each processing block
2. Account for interactions across different processing blocks
3. Adjust the sequence of processing blocks for optimization

Integrated Packaged Solutions
Delivering gas treating solutions via packaged modular process units can provide clear economic and schedule advantages for small and mid-sized projects, particularly in situations of distributed (or remote) gas reserves or when the lead-time for start-up of gas processing units represents a critical path element.

Individual packaged process units can be integrated to ensure overall system flexibility is optimized. This capability played a vital role in the rapid development and success of the U.S. wet shale gas industry and is likely to contribute to the success of the development of sub quality and unconventional gas in other parts of the world.

Conclusion
Gas projects in some parts of the world will require more complex processing solutions as sub quality and/or remote and distributed reserves are developed over the coming decade. UOP believes an integrated design approach with an emphasis on flexibility for both operations and investment decisions will prove critical to successfully monetizing these new gas resources. Flexibility is important due to the complex interrelationship among (i) input upstream factors, (ii) interactions among the processing plant functional blocks, and (iii) overall delivered project economics and/or downstream commitments. Furthermore, incorporation of modularized process units into an integrated package can accelerate project schedules and help stage investment decisions. UOP remains committed to enabling both large integrated gas plants and smaller distributed gas reserves delivered through its diverse portfolio of gas treatment and hydrocarbon management offerings.

by Tim Foley

The expansion of shale gas extraction and production of associated natural gas liquids (NGLs) is creating new opportunities in the petrochemical industry. NGLs production growth, especially in the US, is resulting in a lower price structure for these raw materials. This is evidenced in the several recently announced propane dehydrogenation and NGLs steam cracking projects in the US. Likewise, cost advantaged NGLs enable the economic production of aromatics from unconventional feedstock.

Cyclar Unit Flow Diagram

The Cyclar Process, produces petrochemical grade aromatics and hydrogen from propane and butane (NGLs) feedstock in a single operating unit. The Cyclar product can be used to directly feed an aromatics complex for the production of para-xylene and benzene. The Cyclar product is also suitable as a high octane gasoline blending component. Further, only fractionation is necessary to produce high purity benzene, toluene and mixed xylenes avoiding the substantial additional costs associated with solvent extraction which is required to purify reformate based aromatics.

The Cyclar process employs a series of reactions, collectively termed “dehydrocyclodimerization,” to produce a mixed aromatics stream from propane and/or butane feeds. The first reaction, the rate limiting step, is the dehydrogenation

of the paraffin feed to mono-olefins. At reaction conditions, olefins then quickly oligomerize to form large intermediates which rapidly cyclize to naphthenes. The final step is then the dehydrogenation of naphthenes to aromatics.

Because the net reactions are endothermic, multiple reaction stages, with interstage reheating, are used to achieve high per pass conversions while maintaining high selectivity to aromatics. The Cyclar process makes use of UOP’s Continuous Catalyst Regeneration (CCR) technology which removes coke, a reaction byproduct, from the catalyst and also reconditions the catalyst. The result is a stable long term operation.

The reaction products are a mixed aromatics stream and a significant amount of byproduct hydrogen. The composition of the mixed aromatics will change slightly over the possible range of feeds, from 100% propane to 100% butane and mixtures in between, while the yield of hydrogen is relatively constant. The mixed aromatics product has very low paraffin content, such that the benzene, toluene, and mixed xylenes can be recovered without the need for an extraction unit. Alternatively, the Cyclar product can be sent to an aromatics complex for the conversion of toluene and xylenes to p-xylene and benzene, valuable petrochemical precursors.

 Cost advantaged NGLs can be converted to high value base chemicals using the Cyclar process. The yield of aromatics will be between 58-60 Wt%, varying slightly with feed composition. An additional benefit is the yield of approximately 5 Wt% of hydrogen, which can be recovered at very high purity if desired. The first application of the technology was a 1,000 barrel per day (BPD) unit in Scotland.

The second commercial unit was designed at ~45,000 BPD and has operated in
the Middle East from the year 1999 through 2013.

by Bill Echt

UOP Selexol™ Process
The Selexol process uses a physical solvent to remove acid gases from synthesis or lean natural gas streams. It is ideally suited for the selective removal of sulfur components to very low levels and/or bulk removal of CO₂. The process uses Dow Chemical Company’s SELEXOL™ solvent made of a mixture of di-methyl ethers of poly-ethylene glycol. The solvent is chemically inert and is not subject to degradation.

Acid gas partial pressure is a key driving force for the Selexol process. Typical feed pressure is greater than 2700 kPa with an acid gas composition of CO₂ plus H₂S of 5% or greater by volume. The product gas specifications achievable depend on the application and feed characteristics and can be as low as 1 ppmv total sulfur with greater than 95% CO₂ capture.

The Selexol process can be used for bulk removal of CO₂ from lean natural gases. When processing associated gas streams, Selexol treating can be applied as a dew point control technology due to co-absorption of heavier hydrocarbons (C₆₊) in the solvent.

The process is ideal for purification of synthesis gas (syngas) streams from gasification of coal, refinery bottoms or biomass. SELEXOL solvent removes the minor amounts of ammonia, HCN and metal carbonyls typically found in the resulting synthetic gas streams. The process can be tailored, depending upon the slate of products to be produced downstream of the gasification unit:

• Selective removal of H₂S and COS in an integrated gasification combined cycle (IGCC) plant, with high CO₂ slippage to the treated product gas and high sulfur levels in the acid gas to downstream sulfur recovery systems
• Near total removal of sulfur to generate high purity H₂ for refinery, fertilizer, chemical or liquid fuels production
• Phased design to initially remove sulfur only, then adding a CO₂ capture section as a second-phase project.

UOP Selexol Process Flow Scheme – H₂S Removal and CO₂ Capture from Syngas

The Selexol process was introduced over 30 years ago and 115 Selexol units have been put into commercial service. The most recent applications have focused on treating of synthesis gas from gasification complexes for power and hydrogen production. Extensive optimization can be brought to the gasification project through the study of integration possibilities, with, for instance, hydrogen purification via UOP Polybed™ PSA systems and/or UOP Polysep™ membrane systems, either inside or outside the Selexol process battery limits.

by Eugene Chang and Roger Lawrence

In December 2012, the Bazan Group, formerly Oil Refineries Limited, successfully commissioned UOP’s Unicracking process at its facility in Haifa, Israel, to produce diesel, liquefied petroleum gas (LPG), naphtha, and kerosene to meet the country’s growing energy demands. The UOP Unicracking unit is the first hydrocracker in Israel, and its successful commissioning offers profit growth and will allow Bazan to meet Israel’s energy demands going forward.

“Israel’s energy demand is significantly higher than its production, and the country relies heavily on imports to meet its growing energy needs,” said Pete Piotrowski, Senior Vice President and General Manager of Honeywell’s UOP Process Technology & Equipment business unit. “This project provides an opportunity for the country to meet its energy demands using domestic refining resources, and UOP is pleased its technology is at the forefront of this important initiative.”

UOP’s cutting-edge hydrocracking technology package has positioned Bazan to be able to expand its operating capabilities and grow its profits in new ways by increasing the refinery’s ability and capacity to produce a more profitable product mix.

“It has been very successful since its introduction exceeding not only the forecasted capacity, but also the efficiency and quality properties,” notes Yaron Nimrod, Chief Technology Officer of the Bazan Group. “The investment has given us excess cracking capacity, which means we can import cheap VGO, crack it, and sell the premium products that come from it.” By implementing Bazan’s streamlining plan and upgrading low-value oil products into high-quality fuels, it was able to post an adjusted net profit of $4 million for the first quarter, compared with a net loss of $34 million in the corresponding quarter. Bazan has also been able to experience a 114% growth in EBITDA and a 318% growth in adjusted operating profit. Additionally, the UOP Unicracking unit has allowed Bazan to shift conversion of their Vacuum Gas Oil feed from their FCC unit to the new UOP Unicracking unit to produce more distillates, which has played a direct role in achieving increased adjusted refining margins of $2.00/bbl.

The successful delivery and application of UOP technology, in conjunction with Bazan’s operations and engineering teams, made this all possible.

UOP Engineering and Service
The engineering design and technology application of the UOP Unicracking unit was executed through the UOP Engineering, Services and Equipment group. Bazan and UOP worked very closely throughout the engineering design phase to ensure that all of Bazan’s needs and expectations were met and the design package was delivered on schedule. UOP’s experienced Field Operating Services and Technical Services teams also provided full commissioning and technical support services. More importantly, in order to meet Bazan’s deadlines, the UOP Field Service team worked to complete the sulfiding and unit start-up in one month and achieved the guaranteed performance.

“We were very, very pleased with the UOP Field Service Advisors. They did an excellent job and were a very helpful crew. They went way beyond their job definition,” said Yaron Nimrod. “The main reason the start-up went well was because of the good preparation and good identification of problems by the UOP service team and the Bazan commissioning team.”

UOP Technology
From its robust catalyst portfolio which includes over 20 different catalysts in the Naphtha, Flexible, Distillate, and 2nd Stage regimes, UOP offers solutions that are able to meet the unique needs of each of its customers. For Bazan, UOP chose DHC-32LT, one of its distillate-selective hydrocracking catalysts which also provides maximum hydrogenation functionality to boost volumetric yields and outfitted the reactor with their advanced hydroprocessing reactor internals (HRI). UOP’s Unicracking Unit has allowed Bazan to reroute Vacuum Gas Oil feed from the FCC to the new hydrocracker, which provides more favorable economics, by producing naphtha, kerosene, and diesel of a very high quality.

UOP’s HRI allows for superior mixing and redistribution of the vapor-liquid feed which allows for improved product selectivity, catalyst activity, and cycle length through even flow distribution throughout the catalyst beds in the reactor. With radial temperature spreads (min-max) of 2-5ºC being observed at the bottom of each of the 7 catalyst beds after initial start-up, guaranteed yields are being achieved with the assurance of maximum cycle length.

UOP Continuing Service
UOP remains committed to helping Bazan achieve all its strategic and economic goals going forward and has been active in providing technical support. Implementation of UOP’s OpAware has allowed for UOP to directly receive daily operating data which has helped UOP to more quickly identify opportunities to optimize operations and maximize profit for Bazan. By using OpAware, UOP and Bazan have been able to identify the apparent underperformance of a key piece of equipment and have worked together to quickly resolve the issue to maintain profitable unit performance.

To learn more about UOP’s Hydrocracking Products and Technology or about UOP’s engineering and technical services, please visit www.uop.com or talk to your local sales representative.

by Kevin Brandner

Are your sea-water condensers summertime limited?

Is your CW quality corroding carbon steel tubes?

UOP is excited to announce that our High Cond tubing for enhanced hydrocarbon condensing is now available in a super-ferritic stainless steel. Previously available in carbon steel and copper alloys, the stainless steel version is ideally suited for:

• Sea water cooling
• Cooling water having impurities that are corrosive to carbon steel
• Services with corrosive process condensing fluids

High Cond tubing is an enhanced condensing technology developed by UOP that is ideally suited for use in horizontal cooling water driven condensers, particularly for condensing light hydrocarbons. The proprietary outside surface of the tube consists of a specialized circumferential fin geometry that has been optimized to minimize condensate film thickness and improve condensate drainage. This three-dimensional enhancement results in a condensing heat transfer coefficient that is roughly 15 times greater than conventional bare tube. This typically translates to an overall heat transfer coefficient that is approximately 2 times higher than bare tube and up to 50% higher than standard low-fin tube of similar metallurgy.

High Cond tube exchangers can operate at lower MTD’s and closer temperature approaches than their bare tube and low fin counterparts. These advantages can be used to debottleneck summertime limited condensers, increase capacity when cooling water supply is limited, and allow columns to run more efficiently at lower operating pressures. For grassroots applications, the required surface area can be significantly reduced for a given duty, resulting in smaller exchangers or fewer shells, and lower installed cost.

UOP’s new stainless steel High Cond tubes are manufactured with supplemental helical fins on the inside of the tube to further improve overall heat transfer performance, and reduce fouling potential of the cooling water stream. The helical fins function to disrupt the thermal boundary layer and create turbulence within the tube.

To learn more about our new stainless steel High Cond tubes, and other tube products for enhanced condensing and boiling, contact your local UOP sales representative or visit www.uop.com.

Facility will house the largest capacity isobutylene production unit in China.

China’s Panjin Heyun New Material Co. will use UOP C₄ Oleflex™ process to produce isobutylene, a key ingredient for fuels and synthetic rubber. This is UOP’s third C₄ Oleflex license in China this year. Panjin Heyun New Material Co. will also use Honeywell’s UOP Butamer™ process which converts normal butane to isobutane thereby maximizing the feedstock utilization to the UOP Oleflex process. Southeast Asia is the world’s largest producer of rubber, and China is the largest consumer, accounting for 33 percent of the world’s rubber consumption, according to a 2012 Research and Markets report. China’s economy is expected to grow about 8 percent this year, further increasing the country’s need for key materials.

“As China’s economy grows, and the need for fuels and rubber rises worldwide, UOP is providing solutions that help producers maximize their output to support demands locally, while capturing a high return on investment,” said Pete Piotrowski, senior vice president and general manager of Honeywell’s UOP Process Technology & Equipment business unit. “UOP technology is currently being used in China to produce about 5 million metric tons annually of key petrochemicals and we look forward to working with Panjin to continue supporting the country’s efforts.”

The new unit, which is expected to start up in 2014, will process approximately 400,000 metric tons annually of isobutane feedstock at its facility in Liaoning Province, China. Honeywell’s UOP will provide the engineering design, technology licensing, catalysts, adsorbents, equipment, staff training and technical service for the project.

The C₄ Oleflex process uses catalytic dehydrogenation to convert isobutane to isobutylene. Compared with competing processes, Oleflex technology provides the lowest cash cost of production, the highest return on investment and the smallest environmental footprint, enabled by high isobutylene yields, low energy and water consumption, and use of a fully recyclable platinum alumina-based catalyst system. In addition, unique to the Oleflex process, independent reaction and regeneration systems are in place that allow continuous use of catalysts for steady-state operations (non swing-bed), which helps maximize operating flexibility, on-stream factor and reliability. Since the technology was commercialized in 1990, Honeywell’s UOP has commissioned nine C₃ Oleflex units for on-purpose propylene production, with the 10th unit scheduled to start-up this year in Russia. There are currently five C₄ Oleflex units in operation, producing nearly 2 million metric tons of isobutylene annually.

Panjin Heyun New Material Co. is a private company that produces key petrochemicals at its facility in Liaoning Province, China.

by Eric Baker, Jessy Trucko and Woo Kyung Kim (SK Innovation, Incheon South Korea)

Introduction
The recent boom in gas field production from utilizing new technologies such as hydraulic fracturing has resulted in abundant production of natural gas. As natural gas exits the well head it decompresses, causing heavier hydrocarbons to condense out of the vapor phase as the temperature and pressure decrease. These condensed heavy hydrocarbons are recovered as liquids commonly referred to as natural gas condensates. Natural gas condensates may cover a wide boiling point range from pentanes, through the light and heavy naphtha ranges, and all the way through the jet fuel and diesel ranges.

Although natural gas condensates fractionate into boiling point ranges that refiners are familiar with, they exhibit very different concentrations and species of mercaptan molecules. The mercaptans present in natural gas condensates are typically linear mercaptans. This, combined with high concentration levels, make these feeds challenging to treat. Two effective options exist for the refiner that would like to refine these lower cost condensates into kerosene or jet fuel – Hydrotreating and Mercaptan Oxidation via sweetening (conversion of mercaptan to disulfide) technology. Although Hydrotreating removes these mercaptans, it requires increased hydrogen supply and capacity in an existing hydrotreater or a large capital cost investment to realize. Alternatively, the UOP Merox™ Fixed Bed Sweetening Unit with Merox No. 10 catalyst technology requires low capital investment and minimum operating cost while producing on specification kerosene or jet fuel.

Customer Specifics
SK Innovation in Incheon, South Korea produces jet fuel from two kerosene sweetening units receiving the same feed blend for the production of jet fuel. The smaller kerosene treater (#1 KMX) was designed by UOP and loaded with Merox No. 10 catalyst. #2 KMX was not designed by UOP and was initially loaded with a competitor’s catalyst. Although SK historically processed a blend of various streams to make jet fuel, they began to produce off-specification jet fuel in #2 KMX when the mercaptan content increased, due to blending RasGas Condensate from the South Pars field (Qatar) in the feed. Unfortunately, SK could not make their desired jet fuel specification consistently with the treating technology and catalyst in #2 KMX. SK needed to process jet fuel through their hydrotreater #1 KGHT so its product could blend with the jet fuel pool and ensure on specification by offsetting high mercaptan product from #2 KMX. Figure 1 details this setup.

Figure 1

SK reloaded a high activity version of the non-UOP catalyst into #2 KMX in late 2009 in an attempt to achieve conversion equivalent to #1 KMX. Once again, SK had to reduce #2 KMX throughput to meet specification. Further addition of the Ras Gas condensate to the feed caused the catalyst performance in #2 KMX to deteriorate quickly and exceeded the maximum internal mercaptan sulfur specification of 20 wppm sulfur and the sales maximum of 30 wppm sulfur (see Table 1). Ultimately, SK switched to an easier to treat feed with less feed mercaptan until a better alternative could be found (see Figure 2).

Table 1

Figure 2

SK continued to compare the performance of #1 KMX with Merox No. 10 catalyst against the catalyst in #2 KMX with the same feed. Over a two month period, SK observed higher levels of conversion across the Merox No. 10 catalyst despite the age of the Merox No. 10 catalyst in #1 KMX. The unique formulation of the Merox No. 10 catalyst increases activity over other treating catalysts (including UOP’s Merox No. 8 catalyst), while maintaining activity in difficult to treat environments by providing increased resistance to fouling by organic acids such as sodium phenolate and sodium naphthenate. Figure 3 below shows the increased stability of Merox No. 10 UOP standard fixed bed catalyst.

Figure 3

Customer Decision
After further evaluation of the data, UOP and SK agreed that despite the differences in reactor vessel design, Merox No. 10 catalyst would be a beneficial replacement of the non-UOP catalyst in #2 KMX. They reloaded with Merox No. 10 catalyst without revamping the unit (drop-in replacement).

SK loaded #2 KMX with Merox No. 10 catalyst and evaluated the performance of the new catalyst. During Performance Testing, SK processed a higher portion of RasGas condensate to #1 KMX and #2 KMX units, increasing the mercaptan load by over 250%. In addition, they were able to realize product mercaptan concentrations of less than 8 wppm sulfur with deceased air injection rates (Table 2).

Table 2

Merox No. 10 catalyst has been in service in the #2 KMX reactor since early 2011 with excellent performance. The catalyst change has allowed #2 KMX to process 72% more mercaptan sulfur while reducing off spec product by more than 50%.

Table 3

In the original configuration, hydrotreated kerosene needed to be added to the jet fuel blend to reduce the amount of mercaptan sulfur in the jet fuel product. This is an expensive product to use for dilution of jet fuel. The new Merox No. 10 catalyst performance meets the specifications of mercaptan sulfur in jet fuel without the need for dilution with hydrotreated kerosene.

Economic Benefit
There are two ways in which the economic benefit of using Merox No. 10 catalyst can be realized. The flow scheme in Figure 4 shuts down the #1 Hydrotreater (#1 KGHT), thus reducing operating costs. Figure 4 shows the flow scheme where the #1 KGHT flow is reduced to zero and the #2 KMX flow is increased to 20 MBPD. The #2 KMX unit operates at 10% of the #1 KGHT unit operating cost, resulting in about six million US dollars ($6 MM) in operational savings to the refinery. This allows the #1 KMX to treat another feed at lower severity and higher through put.

Figure 4

Conversely, an increase in profit to the refinery can also be calculated by considering the feed costs. Use of Merox No. 10 catalyst allows SK the option of operating with the original flow configuration, leaving the #1 KGHT running to make jet fuel. The increased processing capacity of #2 KMX leaves #1 KMX available to process another stream and increases jet fuel production by 33%, as per Figure 5. In this case, the increased profit is due to processing a larger amount of cheaper condensate feed. An additional refinery profit of 6 million US dollars ($6 MM) can be realized by the ability to treat less expensive and more difficult to treat feed.

Figure 5

Conclusion
Merox No. 10 was able to significantly improve the profitability of the SK-Incheon refinery. The activity and stability benefit of Merox No. 10 catalyst allowed SK to process a difficult-to-treat condensate in higher quantities and allowed them to off-load one of their Hydrotreaters. SK is pleased with the operations of both Kerosene Merox units loaded with Merox No. 10 catalyst and UOP is looking forward to continued future collaboration. UOP has completed the design of two more Merox process units for the SK Incheon Refiners and is currently in discussions to revamp the existing #2 KMX to a UOP jet fuel Merox Reactor.

By David Myers, Greg Funk and Bipin Vora

In North America, shale gas and shale gas liquids are reviving the petrochemical industry, while at the same time lowering energy prices and improving overall refinery margins for North American refiners. Shale gas provides refiners with opportunities for diversification of feedstock and product and capitalizes on the financial benefits this diversification brings through market cycles. Shale gas also introduces new potential business models for projects, including joint ventures between refining and petrochemical companies or joint ventures between regional independent refiners. Technology innovations and the availability of lower-cost raw materials have played a major part in shaping the petrochemical industry. For example, and in the case for most modern petrochemical products, North America, Western Europe and Japan led the production of methanol from the 1960s to the 1980s. However, due to the increasing discovery of large gas reserves in places like the Middle East, Trinidad, Tobago, Chile, and Venezuela, and resultant-increased natural gas production, methanol production shifted from these industrial-consuming nations to sources of more affordable natural gas. The increased oil and gas production in the Middle East provided an abundant supply of ethane from the associated gas recovery. As a result, throughout the last two decades, a large portion of the growth in ethylene production was in the Middle East via ethane cracking. Because of this, there had been little growth in North American ethylene production in the same period. In fact, several smaller crackers were shut down. Now, with the discovery and development of shale gas and abundant cost advantaged ethane, North America is where we see the greatest potential growth.

Estimates of known natural gas reserves are increasing as new discoveries of unconventional gas reserves increase. The U.S. in particular has increased natural gas production substantially by increasing shale gas development over the last five years. This increased production has made natural gas more affordable in the U.S., benefitting the refining, petrochemical and mid-stream industries through low cost energy. Natural gas, in terms of its energy content, is significantly cost advantaged relative to crude oil. In the U.S., not only has natural gas production increased, but the production of natural gas liquids (NGLs) have increased – namely ethane, propane and butane.

After more than two decades of minimal activity, the availability of ethane and propane from NGLs at a cost effective price has revived the olefins industry. A number of new ethane cracker projects and propane dehydrogenation projects are moving forward. What does all this mean for the refiners in North America? How can they take advantage of this natural gas and NGLs boom?

Opportunities from Shale Gas Monetization - Methane

Abundant methane and associated low natural gas prices are two key factors that make the perfect environment for a gas-to-olefins (GTO) play in North America based on methanol conversion to olefins – ethylene and propylene. Methanol-to-olefins (MTO), though new to the North American market, is already a reality in China and has been since 2010.

End-products of transportation fuels versus light olefins pose fewer logistical issues for product distribution or handling, UOP believes that a pathway from shale gas to olefins (or coal to olefins) provides a route with significantly higher profitability. The first step in a coal to liquid (CTL), gas to liquid (GTL), Methanol-to-Gasoline (MTG) or MTO process is conversion of coal or natural gas to synthesis gas. For CTL and GTL the second step is conversion of synthesis gas to liquids via Fischer-Tropsch (FT) technology. For MTG or MTO, the second step is conversion of synthesis gas to methanol followed by gasoline production in the MTG process or the production of light olefins via the MTO process.

Opportunities from Shale Gas Monetization - Propane

In 1990, there were two primary sources of propylene able to meet the worldwide demand: steam crackers for ethylene production using propane and heavier feedstocks and refinery FCC units. Both primary propylene production sources at that time were from byproduct production and not on-purpose propylene production. With substantial ethane-based ethylene production in North America and the Middle East, the growth in propylene from steam crackers has not kept pace with propylene demand. While some refiners have decided to operate their FCC units in a high severity mode to increase the production of propylene, declining gasoline demand in Europe and North America has limited the overall growth in propylene production from refineries. These trends have created a gap between propylene demand and the supply from conventional sources.

This gap promises to further widen as steam cracker feed stocks continue to shift to cheaper ethane. Demand and corresponding production of propylene is increasing significantly, production from conventional naphtha cracker and refinery sources can not keep pace with demand growth, and now there is a need for on-purpose propylene production technologies, such as methanol to olefins (MTO) and propane dehydrogenation (PDH) to fill the “propylene gap.”

The figure shows the yield of propylene from different processes (steam cracking, FCC, High Severity FCC, PDH and MTO) using different raw materials. As shown, propane dehydrogenation (PDH) provides the highest yield of propylene. This, combined with low capital intensity ($/MT light olefin), has led to wide market interest in PDH in the past several years.

Yields of Various Propylene Production Processes

Opportunities from Shale Gas Monetization - Butane

Butanes are also coming on to the market as a result of shale gas development in North America. Cost-advantaged butanes can provide opportunities for refiners to diversify feedstock while making similar products to those they make today, namely gasoline blending stocks.

The Oleflex dehydrogenation unit can be easily integrated with downstream conversion processes, such as alkylation, to produce high octane alkylate, etherification to produce MTBE or ETBE for the export market, or dimerization of isobutene followed by hydrogenation to produce high octane isooctane. The hydrogen from the dehydrogenation can be used to hydrogenate isooctene to isooctane, a high octane gasoline blending component. The UOP process for this combination is the UOP Indirect Alkylation (InAlkTM) Process.

A renewed interest in isobutane dehydrogenation has re-surfaced in the last two years, mainly centered in Asia. In addition to gasoline blendstock production, there has been interest in isobutylene production for high-purity isobutylene via MTBE cracking as well as isoprene production.

In 2012, UOP began to see interest in isobutane dehydrogenation again in North America. Dehydrogenation and subsequent upgrading of stranded butanes to alkylate or ethers for domestic use or export use presents an interesting alternative for stranded butanes.

Summary

Shale gas in North America is reviving the petrochemical industry due to the abundance of low cost NGL ethane. After almost two decades of very little activity, a number of new ethylene projects based on ethane are moving forward and several projects are under consideration for conversion of shale gas methane to gasoline and other transportation fuels via MTG and GTL. Multiple PDH projects have been announced in North America predominantly by mid-stream and petrochemical producers.

The time for diversification to enable un-matched operating flexibility in the North American refining industry is now. To learn more opportunities from shale gas monetization, visit uop.com.

Country shows strong support for biofuels production and has significant feedstock potential

Green Jet Fuel produced using Honeywell’s UOP Renewable Jet Fuel process powered the first commercial flight in Colombia operating with renewable jet fuel.

A LAN Airbus A320 aircraft traveled with 174 passengers from Bogotá El Dorado International Airport to Santiago de Cali, Colombia. One of the aircraft’s two engines was powered by a 30/70 blend of Honeywell Green Jet Fuel and petroleum-derived jet fuel. The renewable fuel was made with natural oils from camelina, an inedible plant that grows in conditions where food crops can not be grown. The flight marked the first time any aircraft in Colombia has flown on renewable jet fuel.

“Honeywell Green Jet Fuel has been proven repeatedly in military and commercial flights as an alternative fuel source that meets increasingly strict emission standards and strict flight specifications,” said Jim Rekoske, vice president and general manager of UOP’s Renewable Energy and Chemicals business unit. “We look forward to provide sustainable energy solutions that help support Colombia’s significant feedstock potential.”

Depending on the feedstock, Honeywell Green Jet Fuel can offer a 65 to 85 percent reduction in greenhouse gas emissions relative to petroleum-based fuels. Each gallon of camelina-based Honeywell Green Jet Fuel burned instead of petroleum reduces net carbon dioxide equivalent emissions by 68 percent.

When used in up to a 50 percent blend with petroleum-based jet fuel, Honeywell Green Jet Fuel requires no changes to aircraft technology and meets all critical specifications for flight.

The UOP Renewable Jet Fuel Process technology was originally developed in 2007 under a contract from the U.S. Defense Advanced Research Projects Agency (DARPA) to produce renewable military jet fuel for the U.S. military. The process technology is fully compatible with existing hydroprocessing technology commonly used in today’s refineries to produce transportation fuels.

In addition to its Renewable Jet Fuel Process technology, UOP has commercialized the UOP/Eni Ecofining™ process to produce Honeywell Green Diesel™ from biological feedstocks. It also has a joint venture with Ensyn Corp. in Envergent Technologies LLC, which offers pyrolysis technology for the production of renewable heat, power and transportation fuels. To learn more about UOP’s developing range of processes to produce green fuels from natural feedstocks, visit uop.com.

Photo courtesy of The Boeing Company

By – Jaime Munoz

The UOP Latin America Refining, Petrochemicals & Gas Processing Conference brought together UOP technical specialists and customers in Viña del Mar, Chile for a three-day event packed with informative presentations and discussion sessions.

The event included presentations from UOP experts and customers as well as posters and exhibits from many loyal sponsors. The event proved to be a valuable experience for all those in attendance.

With significant new oil and gas reserves and a growing economy, Latin America presents many opportunities in oil, gas and petrochemicals. The Rio de Janeiro office continues to expand and further reinforce UOP’s commitment to position itself to better serve customers and understand their needs.

By – Lauren Levy and Joe Zimmermann

Last month, 120 customers, sponsors and UOP employees attended the Oleflex Technology Users’ Conference in San Antonio, Texas. The conference was co-hosted with Valero, an international manufacturer of transportation fuels and petrochemicals. Attendees represented customers in China, Southeast Asia, India and the Middle East. In addition to learning about Oleflex unit optimization, troubleshooting and best practices, attendees networked with colleagues during a reception, poster session and dinner.

The UOP Oleflex process for propane dehydrogenation (PDH) to produce on-purpose propylene was first commercialized in 1990 [6]. The plant, located in Thailand, was the world’s first PDH unit. UOP’s Oleflex technology was developed utilizing know-how and experience gained from two previously commercialized UOP technologies from the early 1970’s, UOP’s Continuous Catalyst Regeneration (CCR) Platforming™ Process and UOP’s Pacol™ Process. UOP’s CCR Platforming Process is widely used throughout the refining and petrochemical industry to produce high-octane gasoline and aromatic rich reformate with more than 235 operating CCR Platforming units in operation today. UOP’s Pacol technology employs platinum catalysis for kerosene range (C₁₀-C₁₄) paraffin dehydrogenation for linear alkyl benzene (LAB) detergent production. This innovative light paraffin dehydrogenation approach offers the industry a positive pressure, continuous reaction-regeneration section CCR-based approach with low capital cost and low energy usage compared with the sub-atmospheric, swing-bed dehydrogenation systems invented during World War II.

Since 1990, a total of 14 PDH units have been commissioned world-wide. UOP’s Oleflex Process accounts for nine (9) of the fourteen (14) operating PDH units world-wide today with more than 2.4 million MTA (90,000 BPD) of propylene production world-wide.

By – Mohammed Shakur

UOP recently hosted the 2013 UOP CCR Platforming Technology Users’ Conference in San Antonio, Texas and Prague.

The two-day conferences provided an invaluable opportunity for technology experts and process operators to learn about the latest advances in CCR Platforming process technology, products, and recent operational and equipment improvements.

There is a third and final CCR Platforming conference planned for Bangkok, Thailand from March 10 to 12, 2014. If you are interested in more information about this upcoming conference or would like to request an invitation, please send an e-mail to Conferences@UOP.com.