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Isolmalk-2 technology

Forrest Purser - noemail@gtctech.com — Mon, 14 May 2012 21:00:00 GMT

The Isolmalk-2 technology has a successful track record in achieving more than satisfactory results. The start up and operation of the unit at the Omsk refinery marks the appearance of a stable and environmentally safe alternative to chlorinated aluminum oxide systems in a world scale unit.

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14-May-12 4:00 PM

High-Performance Trays Alone do not Guarantee Performance Improvements

Mon, 07 May 2012 16:00:00 GMT

High-performance tray does not itself determine the effectiveness of the whole column. Other distillation equipment plays a vital role in a successful column revamp.

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7-May-12 11:00 AM

Optimize Design for Distillation Feed

Marketing - noemail@gtctech.com — Tue, 30 Aug 2011 15:00:00 GMT

Technical considerations for feed location. Selecting optimum feed location is critical to maximizing distillation column performance. Improper feed location of a distillation column can downgrade column performance; the degree of separation is decreased at the same reflux/boil up ratio or the higher reflux/boil up ratio is required to maintain the degree of separation.

An ideal feed location is feeding to a section of the distillation column where column internal liquid traffic composition is similar to feed stream composition. In this case, it can minimize the composition gradient between feed stream and distillation internal fluids. In distillation column operations, it is often seen that actual feed compositions are changed from original design conditions. In case of significant deviation, discrepancy between column internal liquid composition and feed stream composition can increase, and results in non-optimum feed location. Therefore, evaluating the feed location is an essential step for a successful distillation unit revamp or optimization.

However, it is very difficult to sample and analyze the column internal liquid traffic composition in most of the distillation columns that are commercially operated. Instead, process simulation modeling has been widely utilized to predict internal liquid composition and determine the optimum feed location in the actual industry design. As feed optimization through simulation modeling is convenient and does not require additional costs for field measurements and laboratory analysis, it seems to be a very convenient procedure on the surface. Nevertheless, reputable simulation software itself does not promise the reliability of simulation modeling. Inherent gaps between actual conditions and theoretical simulation modeling should not be ignored (1). The appropriate simulation flow sheeting methodology is necessary to bridge between actual conditions and simulation model. It is common for improper simulation modeling to give misleading results regarding the optimum feed point location and cause poorer column performance than expected.

Key ratio plotting is a useful tool to evaluate optimum feed location in simulation modeling. This key ratio is usually expressed as the mole fraction ratio of light keys to heavy keys in a semi-logarithmic scale chart. A benefit in using the chart is that retrograde distillation due to non-optimum feed location can be visually identified. Optimum feed location can be graphically selected through the chart. Meanwhile, it should not be overlooked that key ratio plotting only shows binary key component behaviors. Light non-key behaviors are not recognized in this plotting (2). Relying on key ratio plotting is dangerous in determining optimum feed location. Reviewing non-key component composition profiles through the column and various sensitivity analyses is also required to insure optimum feed location.

Arranging multiple feed locations to a single distillation column is one of the solutions for a column in which feed compositions are frequently varied. Actual feed location can be switched to suit varying feed composition. Switching methods can be arranged either by manual block valves or automatic control valves. This design is usually feasible in a trayed distillation column. It is difficult to arrange multiple feed locations in most packed column cases unless an extra bed is inserted to allow an alternate bed.

Feed temperature. Feed temperature is one of the major factors in influencing the overall heat balance of a distillation column system. Increased feed enthalpy can help reduce the required energy input from the reboiler at the same degree of separation. Installing a feed pre-heater is a very common process option to minimize reboiler heat duty. If the feed pre-heater can be integrated with other valuable process streams (as a heating medium), overall energy efficiency of the distillation system can be improved further. A simple heat integration in the distillation block is heating feed streams using the bottom product.

However, increasing feed temperature does not always improve the overall energy efficiency of a distillation unit. Excessive feed temperature increments can cause a significant amount of flash of heavy key and heavy non-key components at the distillation column feed zone. In this case, a higher amount of reflux stream is necessary to maintain required overhead distillate purities. This augmented reflux ratio thus requires a higher boil-up ratio. Overall energy efficiency is eventually aggravated (3). Therefore, carefully reviewing feed temperature and phase is critical to minimize the distillation unit’s overall energy consumption. Identifying feed condition at a reliably measured feed temperature should be conducted to evaluate optimum feed conditions. Sensitivity analysis is a required step as well.

Internal feed-distributor design. The importance of the internal feed distributor cannot be ignored in distillation column feeding optimization. The equilibrium stage basis simulator predicts distillation column performance based on ideal mixing between feed and column internal traffic. This means that the feed distribution quality is not reflected in the equilibrium stage calculation result. Therefore feed distribution quality should be evaluated separately to ensure that simulated distillation column performance predictions are met.

Fig. 1: Feed distributor and four-pass top tray with two off-center downcomers

In real distillation column operation, feed distribution quality influences overall performance. Non-optimized feed fluid distribution can cause non-uniform concentration across a distillation column cross-sectional area and result in downgrading performance. The importance of feed distribution is emphasized when a distillation column has multi-pass trays and/or packing. In multi-pass trays, it is essential that uniform internal liquid to vapor (L/V) ratio in each section shall be maintained (4). Also, the feed distribution ratio shall be matched to tray L/V ratio as closely as possible for best performance. Otherwise, poor feed distribution can cause an imbalanced L/V ratio in each pass. In an imbalanced L/V ratio, the reduction of tray efficiency can be observed and non-uniform froth height generation can reduce overall column capacity.

Non-optimum tray layout selection can increase the difficulty of feed distribution. A typical example is when the distillation column’s top tray is configured with two off-center positioned downcomers in four-pass-tray geometry. In this geometry, an internal feed/reflux distributor has to be fed to one center and two side inlets. With a conventional distributor design, this almost guarantees that the split of liquid flow was

not proportional to the vapor from each pass. Poor feed/reflux distribution to the tray inlet panel causes an uneven L/V ratio in each active area.

If the top tray is converted to the tray with two sides and one center downcomers, feed/reflux distribution problems can be resolved. However, this conversion requires complete layout changes of all trays in the column, which may not be feasible in a revamp solution. Since it requires high modification costs, it is not a feasible solution in most cases.

Alternatively, this feed maldistribution can be fixed by an enhanced feed distributor design. Installing controlling orifices can split liquid flow to match the tray pass liquid ratio. Fig. 1 displays the feed distributor for four-pass trays with two off-center downcomers. Since controlling orifices are positioned inside distributor arms, these features are not revealed in Fig. 1. A drawback of this design is creating additional pressure drop through the feed/reflux distributor, thus influencing pipe line hydraulics. Therefore, it is necessary to check whether sufficient driving force is still maintained at a higher feed distributor pressure drop scenario.

A packed column is more vulnerable than a trayed column with regard to feed distribution. Like multi-pass trays, a trough-style liquid distributor with multiple primary troughs (parting boxes) requires uniform incoming liquid distributions to multiple primary troughs. Otherwise, uniform liquid distribution cannot be maintained at the liquid distributor component irrigating the next packed bed.

Proper internal feed distributor sizing is also necessary to achieve uniform feed distribution. High feed fluid velocity can allow more fluid flow at the end of the distributor. Pressure drop among the entry header, lateral arm and discharge hole needs to be optimized. It is usually recommended that progressive pressure drop increments through the feed distributor provide adequate feed distribution. In case of a packed tower trough-style distributor, high inlet liquid velocity can cause liquid splashing allowing liquid flows outside the primary trough(s) of the gravity distributor. Slightly submerged guide-tube installation with properly sized discharge holes can help prevent liquid splashing.

External feed line configuration. Inappropriate external feed configurations also influence distillation column performance. If feed flow is split and introduced to the distillation column through multiple locations, all multiple branch pipes shall be symmetrical. Otherwise, feed flows are not introduced in uniform manners and column performance is influenced. Unless external feed-line balancing is strongly specified in process design materials, such as piping and instrumentation diagrams (P&ID’s) and process data sheets, this line balancing may be overlooked during the final piping design.

External feed line geometry is also a critical issue when two-phase fluid is formed in the feed stream line. Certain distillation columns, such as refinery multi-product fractionators, are inherently designed with two-phase feed conditions. Quite a few energy saving projects specify two-phase feed conditions.

Fig. 2: Original process configuration

As is well-known in the industry, a two-phase feed condition necessitates more complex design steps than a single-phase feed condition. Undesirable two-phase flow patterns are prone to causing unit troubles including entrainment, flow instability, temperature and/or pressure fluctuation, hammering and pipe or equipment erosion(5). It is generally known that slug flow regime should be avoided at two-phase feed inlets. A highly aerated slug can act like frothy surge and can cause not only column instability but also severe hydraulic pounding and distillation equipment damage (6). For a particular vacuum tower inlet, a mist flow regime can create liquid entrainment in the flash zone (7). At high two-phase flow velocities, most of the liquid components are turned to mist droplets and distributed into the vapor phase. This liquid mist is prone to be entrained in the vacuum tower flash zone and impacts distillate product yield and/or qualities.

Fig. 3: Reflux rate vs. feed stage at same solvent product purity.

Understanding two-phase flow patterns and proper piping geometry is required to avoid unit troubles. However, it is very difficult to identify two-phase flow pattern in an accurate manner. There is no reliable calculation method to predict void fractions for pressure drop and fluid residence time yet. Due to a lack of a universal model, two-phase flow pattern prediction is varied upon the model chosen. Graphical and empirical methods are widely used as well. Design practices regarding piping geometry and fitting methods are available in the industry.

Case study. The case study demonstrates how column performance is improved by distillation column feeding optimization. The solvent recovery column function is to separate water and impurities from spent hydrocarbon solvent and to supply regenerated solvent back to the main process unit. Using contaminated solvent as the feed stream, a reflux stream combines with the feed line and is pre-heated prior to entering the column at one single point located at the column’s top. Water and other impurities are stripped from the hydrocarbon solvent and purified solvent is produced at the bottom of the column and recycled back to the main process unit. The original solvent recovery column configuration is described in Fig. 2. As capacity of the main process unit is expanded, the capacity of the solvent recovery column should also be increased to supply enough solvent to the main process unit. However, the solvent column’s maximum capacity was lower than the required capacity.An engineering firm which conducted the main process unit expansion work originally evaluated the solvent recovery column capacity expansion. The expansion study concluded that the existing column diameter was not large enough to handle the required column internal traffic and implementing a larger diameter column with other periphery equipment modifications was suggested. Since this modification plan required a high capital expenditure and a long shutdown period, this modification scenario was not accepted in the given overall project schedule and budget. A more feasible modification scenario was desired to meet the project schedule as well as the performance targets.

Fig: 4: Key ratio plot

An alternative set of unit evaluation and optimization studieswas conducted by another party. The evaluation started with the identification of the root cause, which is an essential step for unit optimization. Operating condition data as well as design documents and materials, were gathered. A preliminary study was done based on operating conditions. The study revealed that the maximum design and simulated duties of the feed pre-heaters were not matched in a reasonable manner. Simulated pre-heater duties at measured feed temperatures were much higher than the maximum calculated heat exchangers’ duties. Meanwhile, all design material data was consistent: P&ID and equipment data sheets showed the same heat-exchanger duties. To confirm the feed pre-heating system design, a field survey was conducted and compared with the design materials. Surprisingly, the field survey disclosed that all design materials were not updated to the real equipment configurations. There were five heat exchangers positioned in the actual feed pre-heating circuit, while the P&ID only showed three exchangers. Through clarifications with the technical/operating staffs, it was found that two more heat exchangers were added to increase feed temperature, but design document materials were not updated. The belief was that higher feed temperature always improves the energy consumption in a distillation unit.

To evaluate the column performance in detail,rigorous simulation modeling was conducted based on operating conditions. The purpose of modeling was to identify the bottleneck point and construct a “base model” for revamping. Obtaining pertinent operating data is necessary for reliable simulation modeling. A review of operating data showed that daily operating conditions were not suitable for simulation modeling. As measured stream volumetric flow rates were not standardized, mass balance closure could not be reviewed. Also, gathered temperature and pressure data were not consistent. A dedicated test run was required to gather reliable operating data. A set of operating data was obtained at the rate just before the maximum operating point in a snap-shot basis. Overall mass and component balance closure data were compiled. Each instrument position was checked and confirmed through a field survey(8).

Before performing rigorous simulation modeling,the thermodynamic package was reviewed in the selected commercial process simulator. It was found that binary interaction parameter and alpha functions were not available between key components in the selected thermodynamic package’s data base. In this case, most of the commercial simulators automatically choose the ideal gas law between components and report results. It is difficult to recognize this assumption unless detailed thermodynamic parameters are reviewed among components. For reliable simulation modeling, binary interaction parameters and alpha functions that were regressed through experiment data were applied in the selected liquid activity coefficient model. Through various sensitivity analyses, tray efficiency of the column was quantified.

Rigorous simulation results indicated that two-phase feed was formed at the operating feed temperature. This feed temperature was much higher than the original design feed temperature. The increment of feed temperature was intended to maximize feed preheater duty and reduce overall energy consumption. However, undesirable two-phase feed caused an excessive hydrocarbon solvent amount in the column overhead system. To maintain product purity specifications of the bottom product, the reflux rate needed to be increased. A higher reflux rate generated more vapor/liquid traffic inside the column and limited column capacity. To destroy this vicious cycle, the feed temperature should be decreased to maintain the liquid feed.

Fig. 5: Modified process configuration

A case study was conducted to check whether the existing feed point was optimum. Required reflux rates were simulated with various feed points at the same bottom solvent purity. These results are displayed in Fig. 3. This figure shows that adding a rectification section helps to minimize the reflux rate at the same product purity and the feeding at Stage 3 shows the minimum reflux rate. Partial key ratio plots are highlighted among stages 1 and 7. Fig. 4 shows key ratio plot changes as the feed point is elevated down. Monitoring key ratio behavior with various feed points shows that retrograde distillation was observed at the Stage 5 feeding.

The solvent recovery unit was modified according to the feed optimization study. The feed tray was relocated from the top tray to the tray matching the third theoretical stage. The reflux stream was no longer combined with the feed stream and was introduced to the top tray independently. The feed temperature was reduced to maintain liquid-phase feed condition. New feed temperature was set at a temperature slightly lower than the simulated bubble-point temperature. In spite of the slightly sub-cooled feed, this temperature maintains a stable liquid-phase feeding against a minor feed composition variation. The internal feed distributor was designed and installed at the new feed location. Since the feed stream contains some fouled materials, the discharge hole size was optimized to prevent potential plugging. It was also found that the control valve flow was reaching the critical flow zone. A new control valve was installed to prevent the choked flow. Modified process schemes are depicted in Fig. 5.

Case Parameter	Unit	Pre-revamp Operation	Post Revamp Operation
Feed rate	GPM	BASE	+ ∆35 %
Feed temperature	^oF	BASE	- ∆68
Feed phase	-	Two-phase	Liquid
Water & other impurities in bottom solvent	wt ppm	BASE	∆0
Reflux ratio (to feed)	Volume basis	BASE	- ∆48 %
Reboiler steam consumption per feed	lb steam/ gallon	BASE	- ∆12 %

Table 1: Solvent recovery column performance comparison

Table 1 summarizes the solvent column’s pre- and post-modification operating data. The maximum feed rate of the column is increased by 35%. The metered reflux rate is significantly improved without sacrificing bottom product purity. The new reflux ratio is only 52% of the previous amount. The reboiler heating medium (steam) consumption per feed is reduced by 12%.

Literature Cited

Lee, S.H, et al, “Optimizing crude unit designs” Petroleum Technology Quarterly 2Q 2009.
Kister, H.Z, “Distillation design,” McGraw-Hill Company, 1992.
Lee, S.H, et al, “Minimizing energy consumption in distillation units” AIChE Spring national meeting April 2009.
Bolles W L, “Multipass flow distribution and Mass Transfer Efficiency for Distillation Plates,” AIChE Journal (Vol. 22, No.1) January, 1976.
Daniels L, “Dealing with two-phase flows” Chemical Engineering June, 1995
Kister, H.Z, “Distillation operation,” McGraw-Hill Company, 1990.
DeGance A.E, et al, “Chemical Engineering Aspects of Two-Phase Flow” Chemical Engineering March, 1970
Kister H, et al, “Sensitivity analysis is key to successful DC5 simulation” Hydrocarbon Processing October, 1998

Authors

Soun Ho Lee is the manager of refining application for GTC Technology US LLC, Irving, Texas and specializes in process design, simulation modeling, distillation equipment design and field troubleshooting for refining and aromatic applications. Mr. Leeholds a BS degree in chemical engineering from Sogang University, Korea.

Michael J. Binkley, PE, is manager of product development for the GTC Process Equipment Technology (PET) group in Irving, Texas. He is a registered professional engineer in Texas with 42 years of experience in mass transfer & separations equipment development & applications. Mr. Binkley has invented several separations equipment advancement-related patents, as well as numerous product trademarks. He earned his BS degree in chemical engineering from Texas Tech University.

30-Aug-11 10:00 AM

Paraxylene Production

GTC's Marketing Department - noemail@gtctech.com — Wed, 15 Jul 2009 14:00:00 GMT

Crystallization technology has improved dramatically over the last three decades. Recent advances in equipment and process control have answered many of the criticisms that have limited its application. Previous designs relied on small units arranged in multiple processing trains and were therefore deemed maintenance intensive. The new equipment is larger, more reliable, and capable of extended run lengths without maintenance.

Paraxylene Crystallization

The C₈ aromatic isomers are difficult to separate by distillation due to their close boiling points. In particular, the boiling points of paraxylene and metaxylene differ by less than 1°C. However, because paraxylene has a markedly higher freezing point than the other isomers, crystallization can be used to facilitate its separation.

Separation of paraxylene by freezing can be accomplished either by suspension crystallization or layer crystallization. For feedstocks containing low concentrations of paraxylene (i.e. 20-24%), suspension crystallization using two or more stages of separation is the only feasible option. For enriched feedstocks, crystallization is a very attractive method of recovery.

CrystPX^SM

Suspension crystallization of paraxylene in the xylene isomer mixture is used to produce paraxylene crystals. The design uses an optimized arrangement of equipment to obtain the required recovery and product purity. Washing the paraxylene crystal with the final product in a high efficiency pusher-centrifuge system produces the paraxylene product. Figure 1 shows a general flow scheme for the technology.

Figure 1. CrystPX Process Flow Scheme

When paraxylene content in the feed is enriched above equilibrium in the case of streams originating from selective toluene conversion processes, GTC’s crystallization process technology is one of the most economical means to produce high purity paraxylene product at high recoveries. The company takes advantage of recent advances in crystallization techniques and equipment to create this attractive method for paraxylene recovery and purification.

The process advantages of this new technology include:

High paraxylene purity and recovery (99.8+ wt% purity at 95% recovery).
Crystallization equipment is simple, easy to procure, and operationally trouble free.
Simple design requires small plot size and low capital investment.
The system is flexible, enabling it to meet market requirements for paraxylene purity.
The system is easily designed to allow for future incremental capacity increases.
Feed concentration of paraxylene is used efficiently.
Flexible technology allows a range of feed concentrations (75-95 wt% paraxylene) to be processed in a single stage refrigeration system.
Design variations are used to recover paraxylene efficiently from dilute mixed xylene feedstocks (22% PX) in a multistage system.

The design uses only crystallizers and centrifuges in the primary operation. This simplicity of equipment promotes low maintenance costs, easy incremental expansions, and controlled flexibility. High purity paraxylene is produced in the front section of the process at warm temperatures, taking advantage of the high concentration of paraxylene already in the feed. At the back end of the process, high paraxylene recovery is obtained through a series of crystallizers operated successively at colder temperatures. This scheme minimizes the need for recycling excessive amounts of filtrate, thus reducing overall energy requirements.

Case Study

LG-Caltex Oil Corporation will use CrystPX crystallization process technology for its new 400,000 tpy paraxylene production unit in Yosu, Korea.

The LG-Caltex Yosu Complex currently operates a world scale paraxylene production facility with a nominal capacity of 700 tpy. This expansion catapults LG-Caltex into the position of number one merchant producer of paraxylene from a single site in the world.

The award marks GTC’s full entry into the paraxylene technology licensing business. In today’s market, with changing feedstocks and market constraints, crystallization technology gives a producer the most flexibility, reliability, and lowest investment cost.

LG-Caltex believes that the CrystPX process is the most simple and reliable technology for its application. It provides and efficient recovery of PX from the feed and the flexibility to adjust process conditions to suit market requirements. The design and equipment are simple and easily procured. A fast startup and trouble-free operation is expected in January 2003.

LG-Caltex, a joint venture between Caltex and the LG Group in Korea, is one of the world’s largest oil refiners and petrochemical producers with a refinery capacity of 650,000 bpd crude oil.

*This article also appeared in Hydrocarbon Engineering.

15-Jul-09 9:00 AM

Optimising Crude Unit Design

Forrest Purser - noemail@gtctech.com — Thu, 14 May 2009 21:00:00 GMT

Real retrofit examples demonstrate how crude units can be successfully optimized with the crude slates currently being processed. Process design strategies are discussed in detail and highlight how retrofit targets are achieved.

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14-May-09 4:00 PM

Optimizing crude unit design

GTC's Marketing Department - noemail@gtctech.com — Wed, 15 Apr 2009 13:00:00 GMT

Introduction

The basic function of a crude distillation unit (CDU) is to provide initial separation of the crude oil feed mixture into the desired fractions to be further processed in the downstream units. The crude unit’s quality of performance impacts heavily on the downstream unit’s performance. A lot of crude units currently operate with different feed slates to their original feed specifications. This change in feed composition often results in inferior crude unit performance and reduces the unit’s run length. Re-optimizing the design and operation of the crude unit with current feed slates is essential to maximize a refiner’s economics. In addition, recent crude oil price fluctuations and increased economic pressure further emphasize the importance of optimizing crude unit performance.

Crude atmospheric column

The crude atmospheric column is the CDU’s core piece of equipment. In a typical crude unit design, crude oil is heated and introduced to the crude atmospheric column’s flash zone. The light products are typically recovered as distillates from multiple liquid product draws and the remaining crude is discharged at the column’s bottom. The original process arrangement relied on a single top reflux flow. The column top reflux provided condensation for all the required product draws, plus the overflash. This approach created high variations in the internal vapor-liquid traffic throughout the column (from column top to flash zone), with a maximum reflux loading at the top and the lower wash section receiving only a small amount of liquid, wash oil. The columns were then sized according to the greatest load, top section internal traffic, which resulted in an oversized column diameter. Moreover, the required size of the overhead condenser was substantially increased.

To minimize these liquid traffic variations, inter-condenser design philosophy was adapted in the crude atmospheric column design. Intercondensers can be configured as either pumpback or pumparound circuits. Figure 1 compares typical internal reflux rate variations through the crude atmospheric column (from column top to flash zone) among three reflux methods.¹ The pumparound reflux method achieves more uniform liquid balancing through the column than the other two reflux methods. This uniformity of liquid enables the column to be sized at a smaller diameter for reduced investment cost. The higher pumparound draw temperatures increase the opportunity for heat recovery for lower energy consumption. In addition, the overhead condenser size is reduced. The main trade-off is that the pumparound circuit design requires more trays and/or packing for heat transfer performance. In summary, the advantages of the pumparound reflux arrangements far outweigh any disadvantages, and as a result it has replaced the pumpback reflux method in most modern crude atmospheric column designs.

Figure 1 - Comparison of internal-reflux rates for three methods of providing reflux.

The presence of a top pumparound circuit depends on overhead distillate yield/fractionation requirements, column top temperature control and overhead condenser size/limitations. Typical crude atmospheric column overhead configurations are depicted in Figure 2 for cases A-C. Case A shows that the top section reflux is provided by a top pumparound circuit only. In this configuration, the column top temperature is relatively high and the chance of water condensing at the column top can be minimized. In addition, the overhead condenser size can be minimized due to a lack of top reflux stream. However, the top pumparound trays and/or packing do not contribute towards fractionation. An additional fractionation section is required to achieve the desired fractionation between the overhead distillate and the first side product, which increases the overall column height.

Figure 2 - Typical crude atmospheric column overhead configurations

Case B depicts a crude atmospheric top section with a top reflux without a top pumparound circuit. This top reflux temperature is usually lower than the reflux through the top pumparound circuit. In this case, fractionation performance between the overhead distillate and the first side product can be maximized at the given column height. However, the required overhead condenser duty is higher and the column top temperature is lower than for Case A.

Case C is somewhat of a compromising design between Cases A and B. This configuration has a top reflux irrigation line as well as a top pumparound circuit. The amount of cold reflux (from top reflux) and hot reflux (from top pumparound) can be controlled at given processing conditions. This configuration is suitable for the crude atmospheric column, which faces high variations in overhead distillates and yields.

Crude column internal vapor and liquid traffic rely heavily on pumparound circuit locations. The number and location of pumparound circuits are determined by crude slate structures, product yield patterns, fractionation requirements, overhead condenser size and other factors. The crude atmospheric column is designed to provide the best performance for specific ranges of crude slates and product yields. Therefore, a large change from design conditions may induce performance downgrading in the crude unit. Fractionation performance between adjacent products requires specific design internal reflux at a given number of fractionating trays or packed bed depth. Crude overhead condenser duty is also determined by design heat balances.

In most cases, the actual crude slate structures processed in the crude unit deviate from the original design ranges. To maintain desired unit performances at changed feed conditions, most refiners adjust and rearrange the pumparound balances. These operation parameter changes shift the column traffic through the crude atmospheric column. The pumparound rate change impacts neighboring fractionation section internal reflux rates, so fractionation performance is affected.²Unbalanced column traffic often results in unit capacity limitations. The crude atmospheric column design should be re-evaluated with current operating blends to ensure the best performance possible.

The following actual retrofit case demonstrates how a crude unit can be successfully optimized, considering a more typical crude blend used by the refinery.

Retrofit background

The crude unit under discussion was originally commissioned in the early 1970s. Charged crudes are heated through two parallel preheat trains and furnaces, and then introduced into the crude atmospheric column. This column separates crudes to intermediate products: unstabilized naphtha, kerosene, light gas oil (LGO), medium gas oil (MGO), heavy gas oil (HGO) and reduced crude (R/C). Unstabilized naphtha is then fed to the naphtha stabilizer to separate the LPG and naphtha. The kerosene stream is transported to the hydrotreating unit. LGO, MGO and HGO are combined to the diesel pool after hydrotreating. Reduced crude is either transported to conversion units or blended to fuel oil.

The crude atmospheric column was originally constructed with four pumparound circuits: one top pumparound and three diesel pumparound circuits. A top reflux stream, which is recycled from the unstabilized naphtha (overhead distillate), is combined with the top pumparound stream before returning to the crude atmospheric column. The amount of top reflux stream is adjusted relative to the unstabilized naphtha boiling range of the processed crudes. To increase the crude charge rate and enhance unit performance, this crude unit had been previously retrofitted. During these prior retrofits, the HGO pumparound and wash sections were converted to structured packed beds. All four side strippers are steam-stripped. Figure 3 illustrates the crude atmospheric column configurations after these previous retrofits.

Figure 3 - Crude atmospheric column configurations - previous retrofit.

To meet required downstream unit balances, especially in the conversion units, the refiner decided to perform a new crude unit retrofit. The targets of this current retrofit were debottlenecking operating limitations and increasing crude unit capacity. One of the unit limitations the refiner faced was that the crude atmospheric column had difficulty processing crude slates containing a high percentage of kerosene boiling range materials. In the winter, kerosene product is usually more valuable than diesel and naphtha. Relieving any limitations on kerosene production was necessary to improve unit economics.

Replacing existing crude column trays with high-performance trays or packing is one of the most economical ways to improve column capacity in terms of overall downtime and cost. However, the preliminary evaluation was that a retrofit of the kerosene side stripper would not meet the required capacity. All four existing side strippers were stacked and erected as one single column shell with the kerosene stripper located on top. Therefore, it was not feasible to modify the shell/vessel to change the kerosene side stripper design only. Plot space and access to the unit were limited too, so adding and/or replacing the side strippers was impossible without substantial cost.

Test run and unit performance evaluation

Prior to any process evaluation, a dedicated crude unit test run was conducted to gather pertinent operating data. The importance of a test run cannot be stressed enough. Daily operating data do not always provide all the required information for reliable process evaluations. A crude slate containing high kerosene boiling range material was selected for the test run, as this represented a typical operating crude slate in the unit. For equipment limitation checking, the test run charge rate was determined as the maximum crude charge rate in which the crude unit operated without loss of fractionation efficiency.

In order to gather pertinent operating data, all associated instruments were calibrated prior to the test run. The measured flow rates were verified via flow meter orifice calculations and storage tankage levels, to establish whether mass balance closure error was within suitable range for reliable modeling.³ Traditional laboratory methods do not provide appropriate characterization for heavy oil boiling range material. The high temperature simulated distillation (HTSD) method was used for the reduced crude stream laboratory test to obtain better heavy boiling range material characterization.

Since distillation equipment pressure drop is related to column traffic, a survey of measured pressure drops across the column was required. This is a useful tool in column troubleshooting and evaluation. In particular, the survey allows the troubleshooter to pinpoint equipment locations that require further evaluation. The measured pressure drop profile through the column showed that the top pumparound pressure drop was over two times higher than the LGO and MGO pumparound section pressure drop on the same basis. In addition, the measured HGO packed bed pressure drop was much higher than expected. This pressure drop survey indicated that the column top and bottom sections might be more loaded than the middle sections.

Reliable simulation modeling is another cornerstone of successful process evaluation. Throughout the modern hydrocarbon industry, simulation is widely used to design and/ or analyze distillation column performance and it has become a basic tool for process engineering. Many design firms rely heavily on simulation modeling to establish heat and material balances. Commercially available steady-state process simulators are regularly upgraded with regards to thermodynamic packages, component and property databases, properties calculation, numerical method algorithms, software interfaces and other capabilities.

Nevertheless, selecting reputable simulation software does not guarantee the reliability of simulation modeling. Accurate simulation modeling still requires extensive knowledge and understanding of the process and equipment that need to be modeled. Inherent gaps between actual condition and theoretical simulation modeling should not be overlooked. It has been observed that unreliable simulation modeling that neglects these issues can lead to design flaws and performance deterioration. In an earlier article,⁴ it was discussed that conventional flow-sheeting topology does not adequately address refinery fractionators such as crude vacuum distillation columns. Actual flash zones operate in a non-equilibrium state, and fluid mixing through transfer lines is highly non-ideal. Conventional simulation topology commonly used in the industry does not predict crude column performance properly. This especially applies to the flash zone, transfer line, and wash and stripping sections.

During this crude atmospheric column simulation modeling, it was observed that conventional topology did not properly simulate energy loss through the transfer lines. Therefore, process solutions based on conventional simulation potentially under- or over-predict operating parameters. Such results may induce a performance shortfall or failure in a retrofit solution. To obtain reliable simulation modeling results, this crude atmospheric column was modeled using modified simulation topology. This updated modeling procedure dissected the column into multiple blocks to model the crude atmospheric column, the furnaces and the transfer line properly. The interval of pseudo components was adjusted to match the obtained laboratory distillation temperature span. Tray efficiency for each fractionation section was determined through various sensitivity analyses.

Root cause identification

This crude unit was originally designed and constructed to process high diesel and low kerosene content crude slates. That is why three pump around circuits were located in the diesel section, while a pump around circuit was omitted in the kerosene section. The design philosophy in this crude unit showed the best performance with diesel-rich and kerosene poor crude slates.

For the first step of root cause identification, the crude slate structure for the test run was compared with previous retrofit design crude slates. The test run crude and previous crude yield structure are illustrated in Figure 4. These yield structures were obtained using blending programs. The blending program predicts recoverable material yield with a clear-cut basis between products and does not take into consideration actual distillation column performance. Nevertheless, this crude structure comparison helps comprehend any deviation between the prior design and current operation environment. This graph shows that the test run crude slate contains much more kerosene boiling range materials than the previous retrofit design crudes. Petroleum gas and naphtha content were also increased in the test run crude slate, while diesel boiling range material percentages are almost the same for the two crude slates.

Figure 4 - Comparison of crude slate structure.

To scrutinize unit limitation and identify the root cause, the column traffic profiles were reviewed at the test run conditions. Existing tray and packing capacities for the test run case were calculated with simulated traffic extracted from the test run simulation. In Figure 5, the red line indicates simulated pumparound capacity at the test run condition. Capacities of previous retrofit design cases are plotted in green. These plots show that the top and HGO pumparound sections were run at high capacities, while the LGO and MGO pumparound sections were run at lower capacities. Relative loads among the four pumparound circuits were not optimized at the previous retrofit design stage, so this problem was exaggerated due to the current high kerosene crude slates.

Figure 5 - Simulated pumparound capacity.

One of the ways to improve pumparound balancing is to shift the top and HGO pumparound loads to LGO and MGO pumparound circuits. However, simple pumparound rate redistribution will impact fractionation in the existing column arrangement. Vapor and liquid traffic is decreased above the section where the pumparound rate is increased.² In this particular column, increasing the LGO and/or MGO pumparound rates would result in a reduction in the internal reflux of the naphtha-kerosene fractionation section and downgrade the separation between these products. One possible result is a reduced kerosene flash point and difficulty in meeting the specification. Simulation modeling for the test run case also verified that the fractionation sections in the crude atmospheric column were overly sensitive to the internal reflux rates. To compensate for this sensitivity, the crude column had been operated with high top pump-around rates and high internal reflux for naphtha and kerosene fractionation. Through these evaluations, it was determined that the pumparound design had not been optimum since the initial design stage. In addition, the crude feedstock change further aggravated the pumparound capacity. It was necessary to optimize the crude column design, including the pumparound rearrangement at current crude slate conditions, for maximum crude unit capacity and performance.

Current retrofit design

Based on the test run simulation results, a new simulation model for the current retrofit was developed. The existing tray performance with simulated traffic predicted that the existing single kerosene draw configuration could not produce the required kerosene yield. The current retrofit target yield required a much larger kerosene side stripper as well. As mentioned earlier, installation of a larger kerosene side stripper was not feasible. To increase the kerosene yield with a minimum mechanical modification scenario, the existing LGO draw was converted to a heavy kerosene draw. In this case, the number of kerosene draws was increased from one to two, while the gas oil draws were reduced from three to two. This retrofit strategy did not require any column nozzle and external piping configuration changes.

With these product layout conversions, the existing LGO and MGO pumparound circuits were converted to new heavy kerosene and new LGO pumparound circuits, respectively. The pumparound balance was optimized between the new LGO and HGO pumparound sections to improve overall capacity as well. The pumparound capacities of the current retrofit design are plotted in blue in Figure 5. These capacities are based on a new higher crude charge rate using new high-performance trays and new structured packing, as part of the current retrofit. A recognizable improvement in pumparound balancing is demonstrated in this graph. Process configuration changes per product and pumparound rearrangement are highlighted in Figure 6.

Figure 6 - Crude atmospheric column configurations after current retrofit.

These product and pumparound rearrangements resulted in a lower logarithmic mean temperature difference (LMTD) for the new heavy kerosene and new LGO pumparound circuits compared to previous services. A careful evaluation of the preheat train was required to make sure the new configuration did not result in a lower preheat temperature to the furnace and/or possibly reduced recovery or higher energy consumption. Some modifications to the preheat train and exchangers were completed to optimize the heat recovery at the new conditions.

An overall heat balance check, including furnaces, showed the desired feed temperature would be achieved at the current retrofit design condition. An existing distillation equipment evaluation with simulated traffic showed that the existing trays and HGO pumparound packing were unable to handle the required traffic at the current retrofit rates. To increase distillation equipment performance, all trays in the crude atmospheric column were replaced with high-performance trays.

One important point when tying simulation design to actual distillation equipment performance involves the effect of internal vapor and liquid distribution and the internal liquid-to-vapor (L/V) ratio in each section of the tower. Figure 7 illustrates the multiple internal vapor and liquid streams in a four-pass tray. Steady-state simulation modeling assumes that the ratios are equal, while in actual operation it is rarely this close. Poorly designed or imbalanced multi-pass trays and/or improper feed arrangements can exacerbate this problem, resulting in lower-than-expected tray efficiencies or, in some cases, a reduced ultimate capacity. Previous references have noted balancing methods for multi-pass trays in order to achieve this L/V ratio.⁵

Figure 7 - Multiple internal vapor and liquid streams in four-pass tray

The top pumparound return liquid distribution design was addressed during the current retrofit. In particular, four-pass trays were used for most of the pumparound circuits, and the existing top tray downcomers were positioned as two off center locations. Liquid must be irrigated to three inlet panels: one center and two side-positioned inlet panels. In this case, it is very difficult to achieve desired distribution using a conventional distributor, as each inlet needs a specific metered amount of liquid. The new distributor coupled with a balanced tray design must meter this liquid properly to insure the new targets are met.

During a previous turnaround, it was found that the top pumparound trays had lost a significant number of movable valve units from the tray decks. Valve/perforation hole wear and corrosion, which are common problems in this section, were the root cause. To alleviate the problem, the top pumparound active areas were replaced with fixed-valve decks. However, there were performance/fractionation variations after this previous replacement. Petroleum gas and naphtha yield structure and cooler performance varied the top pumparound circulation rates significantly. The liquid and vapor profile from the top to the bottom of the pumparound varied greatly. Detailed tray evaluation at various ranges of operation and crude slate structure showed an excessive tray-opening area, causing heavy weeping at the top tray of the pumparound. A review of tray drawings revealed that the same number of holes (same valve open area) was applied for each pumparound tray deck to simplify tray manufacture and reduce cost. For the current retrofit design, each top pumparound tray open area was re-arranged and optimized per simulated traffic. Tray open areas were progressively increased through the section to mitigate weeping. High-performance fixed valves were applied to meet the required top pumparound capacity.

The transition section design between fractionation and the LGO pumparound section also had distribution issues. However, space constraints meant it was not a simple matter of designing a feed pipe and transition to balance the tray flows. In this case, the number of passes for the LGO pumparound was changed from four to two, as four-pass trays were unnecessary. This change coupled with the new pumparound return piping alleviated any distribution issues.

The structured packing for the HGO pumparound was replaced with new packing as well. To increase packing capacity, a higher capacity packing was chosen. In this case, a big concern was a possible reduction in heat transfer efficiency, as higher capacity packing will generally result in lower efficiencies. However, careful understanding of the heat transfer coefficient calculations will allow the process designer to meet any duty requirements.

The bottom stripping section was also modified to maximize distillate recovery. Steam stripping trays are operated at low vapor and high liquid traffic. While a high amount of reduced crude is transported through the stripping tray downcomers, only stripped hydrocarbon and stripping steam are included in the vapor phase. The result is that the active area is not a controlling factor in determining stripping section capacity. Oversized open areas over an active area decrease vapor velocity. This low velocity does not generate enough froth for vapor and liquid contact and downgrades stripping efficiency. Weeping at the bottom stripping trays is a common problem in this section, especially as the vapor traffic at the bottom stripping tray contains only the stripping steam. The original stripping section consisted of five four-pass trays. Although five trays were assigned to this section, it was found that the last stripping tray was designed as a blind tray. The existing four-pass tray did not provide adequate steam distribution across the active panels and caused vapor channeling. This cross channeling can downgrade stripping efficiency as well. Increased stripping steam rates were used to compensate for the efficiency loss at the penalty of increased condenser load.

For the new tray design, the flow path quantity was reduced from four to two. New two-pass trays with optimum downcomer design would be able to handle the required flow rates, and many of the distribution issues would easily be solved. The average flow path of the liquid on each tray was increased as well, which helped enhance tray efficiency. The tray open area was optimized to maintain good vapor velocity. Special active area modifications also helped maintain the plug flow regime in the liquid phase. Cross channeling was corrected in the new tray design. The new light kerosene stripper trays were also modified with similar design philosophies.

Startup

The crude unit was shut down and modified according to the current retrofit design. The startup procedures of the crude distillation unit were reviewed and updated to match the current modifications. The effect of the lower pressure drop through the column and high-performance trays needed to be evaluated for successful unit startup and operation. Every aspect of the startup was considered to avoid undesired delays that might impact the refiner’s economics.

High-performance trays in this crude atmospheric column utilize a dynamic downcomer seal design. In this advanced design, the downcomer clearance is greater than the outlet weir height. The downcomer sealing is easily maintained with adequate liquid flow to prevent vapor from bypassing up the downcomer. However, extremely low liquid and vapor rates (below normal minimum operating conditions) may be encountered during initial startup. Thus, the downcomer seal may be lost, resulting in poor fractionation and other operating difficulties.³ To eliminate potential downcomer unsealing problems, the initial crude charge rate and the pumparound rates at startup were increased from previous startup initial charge rates, and the refinery operations team was trained in how to avoid such problems.

Light/heavy kerosene and LGO draw temperatures were also changed per pumparound rearrangement. The temperature profile change increased the difficulty in establishing heat and material balances during startup. Before increasing the initial charge rate to target capacity, all operating parameters were monitored and reviewed sufficiently after establishing heat and material balances at the initial charge rate.

Post current retrofit performance

This crude unit was successfully revamped and its target capacity was met. Table 1 summarizes pre and post current retrofit operating data. Two sets of test run data are shown to check unit performance. Test run 1 and 2 indicate operating data at kerosene- and diesel rich crude slates, respectively.

Table 1

Overall unit capacity has been expanded and kerosene-rich crude slates are processed without any limitation. Although the number of diesel pumparound circuits was reduced, the crude unit produces much higher diesel yields.

Column fractionation efficiencies are substantially improved. Fractionation efficiencies among products are enhanced at higher distillate production rates, lower stripping steam injection rates and lower furnace outlet temperature. The final processed crudes are actually heavier feedstock containing more atmospheric residue boiling range material. Separation between diesel and reduced crude is improved and the reduced crude 5% distillation temperature is increased, indicating improved diesel recovery.

Pressure drop is maintained or reduced at higher product yields. Lower flash zone pressures lift more distillates at the same furnace outlet temperature or reduce the furnace outlet temperature at the same distillates. This pressure drop improvement also help to minimize the energy consumption of the crude unit. Stripping steam savings help the refiner’s economics too.

References

1. Perry RH, Green D, Perry's Chemical Engineers' Handbook, McGraw-Hill Company, 6th Edition.

2. Libermann N P, Troubleshooting Process Operations, Pennwell Publishing Company, 3rd Edition.

3. Kister H Z Distillation Operation, McGraw-Hill Company, 1990.

4. Golden S, et al, Improved flow sheet topology for petroleum refinery crude vacuum distillation simulation,

44th Annual CSChE Conference, 1994

5. Bolles W L, Multipass flow distribution and mass transfer efficiency for distillation plates, AIChE Journal,

22,1, January 1976.

Authors

Soun Ho Lee is the Manager of Refining Application for GTC Technology, Irving, Texas, and specializes in process design simulation and troubleshooting for refining applications.

Ian Buttridge is the Manager of Technical Marketing for GTC Technology, Irving, Texas, and specializes in column revamps and energy saving for distillation trains in refining and petrochemical applications.

Jay J (Jae Jun) Ha is Senior Process Engineer of the project execution team for GS Caltex Corporation, Yeosu, Korea, and works in various retrofit projects including crude units.

This article also appears in PTQ Q2 2009 Issue (www.eptq.com )

15-Apr-09 8:00 AM

GTC Technology to exclusively license advanced sulfur recovery technology from ConocoPhillips

noemail@gtctech.com — Wed, 15 Feb 2012 16:00:00 GMT

HOUSTON, Texas, February 14, 2012 — GTC Technology, a global licensor of innovative process technologies, process equipment technology and mass transfer solutions, is pleased to announce an exclusive, worldwide, agreement with ConocoPhillips for its Selective Partial Oxidation of Sulfur (SPOC™) technology for sulfur recovery. ConocoPhillips is the third-largest integrated energy company in the United States, and the fourth-largest refiner worldwide, with a long heritage of technology innovation, including technologies for LNG, delayed coking, clean fuels, gasification and alkylation.

SPOC™ technology is the most significant innovation in the “modified Claus” technology space in the last 30 years. Given the prevalence of “modified Claus” technology, SPOC™ technology may be expected to impact the global sulfur recovery space for the foreseeable future. The agreement expands GTC’s platform of acid gas removal technology, which currently includes GT-CO₂™, a process technology for CO₂ removal; GT-SSR™, a Claus process for sulfur recovery; and GT-DOS™, an innovative direct oxidation technology.

“SPOC™ technology eliminates the Claus furnace and addresses many of the endemic issues associated with conventional modified Claus technology, such as COS and CS₂ formation, and challenges with start-up and shut-down,” said Dr. Matt Thundyil, Sulfur Business Leader for GTC Technology US, LLC. “In addition, it is anticipated to offer better efficiencies than conventional modified Claus technology with significant savings in capital cost. This technology may also be able to upgrade conventional modified Claus plants, delivering improved performance with minor capital outlay.”

“This collaborative agreement with GTC allows us to bring valuable innovation to a marketplace that has been seeking better technology. ConocoPhillips developed and tested the SPOC^tm technology and believes it sets a new cost and performance benchmark for sulfur removal processes,” said Merl Lindstrom, Interim Senior Vice President of Technology at ConocoPhillips.

GTC signs agreement with RATE for gas processing and sulfur recovery technologies

noemail@gtctech.com — Mon, 07 Nov 2011 15:00:00 GMT

HOUSTON, Texas, November 7, 2011 — GTC Technology, a global licensor of innovative process technologies, process equipment technology and mass transfer solutions, is pleased to announce a worldwide agreement with Rameshni & Associates Technology and Engineering (RATE) for gas processing and sulfur recovery solutions. RATE is a privately held company in Monrovia, CA, with extensive experience in designing large world-scale gas processing plants, sulfur removal units, sour water strippers and sulfur degassing units as well as sulfur recovery technologies, tail gas treating technologies, and Total Sulfur Management for meeting new environmental regulations.

The agreement expands GTC’s platform of acid gas removal technology, which currently includes GT-CO₂℠, a process technology for CO₂ removal; GT-SSR℠, a Claus process for sulfur recovery with over 60 licenses; Crystasulf^®, a liquid-phase Claus process technology for sulfur recovery; and GT-DOS℠, an innovative direct oxidation technology. GTC expects this agreement to expand its offering to greater than 2,500 tons/day of sulfur and 4,000 MMSCFD (4,000,000 NM3/H).

“RATE has world renowned experts with a long track record in designing world scale plants,” said Dr. Matt Thundyil, Sulfur Business Leader for GTC Technology US, LLC. “We are pleased to be able to work with them. We will be able to deliver greater value to our clients, and continue our exceptional track record in commercializing innovative technologies for the energy industry.”

“GTC has a worldwide reach, EPCm capability, and its advanced mass transfer technologies provide excellent synergies for amine and sour water systems. This agreement will allow us to offer a first class design with pull through capability to our customers,” said Mahin Rameshni, President and CEO of RATE.

GTC Technology signs agreement with TDA Research for sulfur recovery through catalytic direct oxidation

noemail@gtctech.com — Thu, 25 Aug 2011 20:00:00 GMT

HOUSTON, Texas, August 25, 2011 — GTC Technology, a global licensor of innovative process technologies, process equipment technology and mass transfer solutions, is pleased to announcea worldwide technology licensing agreement with TDA Research for sulfur recovery from hydrogen sulfide through catalytic direct oxidation. TDA Research is a privately held R&D company in Wheat Ridge, Colorado, which develops new materials (polymers, carbons and ceramics), catalytic and sorbent-based chemical processes and military and aerospace components.

The agreement expands GTC’s platform of acid gas removal technology, which currently includes GT-CO₂^SM, a process technology for CO₂ removal; GT-SSR^SM, a Claus process for sulfur recovery with over 60 licenses; and Crystasulf^®, a liquid-phase Claus process technology for sulfur recovery. GTC expects the catalytic direct oxygen technology to apply to a range of 0.2 to 300 tons per day.

“Direct oxidation catalyst technology provides a significant advance in sulfur recovery,” said Dr. Matt Thundyil, Sulfur Business Leader for GTC Technology US, LLC. “We will be able to deliver greater value to our clients, and continue our exceptional track record in commercializing innovative technologies for the energy industry.”

GTC Technology awarded mass transfer equipment contract for Ruwais Refinery Expansion Project

noemail@gtctech.com — Thu, 03 Feb 2011 21:00:00 GMT

HOUSTON, Texas, Feb. 1, 2011 — GTC Technology, a global licensor of process technologies, process equipment technology and mass transfer solutions, is pleased to announce a contract to design and supply mass transfer equipment for the Ruwais Refinery Expansion Project, a mega-sized grassroots expansion to increase refining capacity. The refinery is owned by The Abu Dhabi Oil Refining Company (Takreer) and the refining facility is located in Ruwais, United Arab Emirates. The expansion project includes 21 process units, off sites and utilities.

After an extensive evaluation process, GTC Technology Korea Co. Ltd., a subsidiary of GTC Technology International, LP, was selected to provide mass transfer equipment for the crude distillation unit, saturated gas plant and residue catalytic cracking unit which is the largest single unit of its kind in the world. The contract includes a giant-sized pre-flash column, crude column and residue fluidized catalytic cracking (RFCC) main fractionator.

“We are proud to be selected to provide our best-in-class mass transfer solutions for the core distillation columns in this mega-sized expansion project,” said Jaeman Cho, president of GTC Technology Korea.

GTC Technology Secures Saudi Aramco Approval, Process Equipment Technology Contract

noemail@gtctech.com — Wed, 11 Aug 2010 13:00:00 GMT

HOUSTON, Texas, August 11, 2010 - GTC Technology, a global provider of process equipment technology and mass transfer solutions, is pleased to announce that it has secured on-going supplier approval and an immediate contract approval by Saudi Aramco, the largest oil corporation in the world, to provide mass transfer equipment through its manufacturing facility in South Korea. Following an extensive contractor review and evaluation process, GTC Technology Korea, a subsidiary of GTC Technology International LP, was selected to provide mass transfer equipment for Acid Gas Treating and Sour Water Stripping Units at the Saturated Gas Plant of the Jubail Export Refinery Project. This 400,000 barrel per day, full conversion facilitated refinery is owned by Saudi Aramco Total Refining and Petrochemical Company (SATORP), a joint venture between Saudi Aramco and Total S.A. Saudi Aramco, Saudi Arabia's state-owned national oil company, restricts products and services to only...

Holly Corporation Selects GTC Technology's Benzene Management Technology for Oklahoma, Utah Refineries

noemail@gtctech.com — Wed, 12 May 2010 14:00:00 GMT

HOUSTON, Texas, May 12, 2010 — GTC Technology US, LLC announced today it was selected by Holly Corporation (NYSE: HOC) and two subsidiaries to provide process design engineering and its licensed GT-BenZap® technology for benzene management and reduction. The licensed technology will support Holly’s efforts for compliance with EPA-mandated Mobile Source Air Toxics (MSAT2) benzene regulations. GTC’s benzene saturation process, GT-BenZap®, will reduce benzene concentration in the reformate gasoline stream at Holly Refining and Marketing’s refineries in Tulsa, Oklahoma and Woods Cross, Utah. GT-BenZap® is designed as a cost-efficient alternative for refiners with limited economy of scale for benzene recovery, or where the refinery is located far away from benzene consumers. “When the demands of MSAT2 required us to make facility modifications, we knew we needed a reliable, yet competitively priced alternative,” said Gary Fuller, Senior...

GTC Unveils New Brand Identity

noemail@gtctech.com — Fri, 12 Mar 2010 14:00:00 GMT

Houston, Texas, March 12, 2010 – Today GTC Technology US, LLC (GTC) formally unveiled a new brand identity. The new identity represents a significant milestone in GTC’s history. The new branding system simplifies and unifies GTC’s identity across all product lines and services in order to better communicate important characteristics and value to customers.

Pinti Wang, President and CEO of GTC Technology noted that “As GTC continued to evolve, we recognized the need to consolidate our visual identity in line with our growth and diversification of products and services in the hydrocarbon processing industry. Our new identity enables us to establish and communicate stronger connections with our clients and strengthen our overall position in the marketplace.”

The new brand is communicated through a new website, marketing literature, presentations, newsletters, and a range of additional marketing materials. “Engineered to Innovate,” is GTC’s unique brand promise to clients and was developed to concisely communicate GTC’s rich heritage of innovation focused on delivering world-class products and services to the hydrocarbon processing industry.

Headquartered in Houston, Texas, GTC Technology US, LLC is a global licensor of process technologies, offering engineering services, process equipment solutions, chemicals and catalysts to the chemical, petrochemical, refining and gas processing markets. With engineering, manufacturing facilities and a knowledgeable sales force located throughout the globe, GTC combines unparalleled industry expertise, powerful research capabilities and innovative thinking to deliver high-quality, strategic solutions for clients worldwide. www.gtctech.com

GTC Technology Opens New Office in Brno, Czech Republic

noemail@gtctech.com — Wed, 10 Feb 2010 17:00:00 GMT

Brno, Czech Republic, February 10, 2010 — GTC Technology today announced the launch of a new office located in Brno, Czech Republic. The new office will focus on serving the European and CIS markets, offering the full range of GTC products and services. The office will house a team of engineering, sales and technical service personnel.

“This move reflects GTC’s interest in reaching one of the international markets we have targeted for development. We are committed to our clients’ success and the new office will provide us with strategic access to better serve our growing regional client base,” said Pinti Wang, President and CEO of GTC Technology.

GTC Europe s.r.o. is a subsidiary of GTC International LP, a global licensor of process technologies, offering engineering services, process equipment solutions, chemicals and catalysts to the chemical, petrochemical, refining and gas processing markets. With engineering, manufacturing facilities and a knowledgeable sales force located throughout the globe, GTC combines unparalleled industry expertise, powerful research capabilities and innovative thinking to deliver high-quality, strategic solutions for clients worldwide. www.gtctech.com

GTC Technology Partners with NPP Neftehim to Offer a C5 C6 Isomerization Technology and Catalyst

noemail@gtctech.com — Tue, 17 Nov 2009 15:00:00 GMT

Houston, Texas, November 17, 2009 — GTC Technology US, LLC (GTC) today announced that it has signed an engineering and exclusive marketing agreement with NPP Neftehim to offer clients a proven mixed metal oxide isomerization catalyst “SI-2” and isomerization technology “Isomalk-2SM”. The new technology is capable of converting unbranched low-octane C5-C6 paraffins to octane boosting isomers with simultaneous benzene saturation in refinery streams. The SI-2 catalyst is a novel, highly effective Pt-containing, mixed metal, sulfated oxide isomerization catalyst. The technology is noted for its higher tolerance to moisture and other impurities and its ability to process a significant quantity of C7 components. “This isomerization technology allows refineries to process a heavier naphtha fraction, which often accompanies the operational changes to meet the MSAT II gasoline specifications for benzene, aromatics and sulfur. This partnership enables GTC...

GTC Technology Becomes a Member of Fractionation Research Inc.

noemail@gtctech.com — Fri, 22 May 2009 21:00:00 GMT

Houston, Texas, May 22, 2009 — GTC Technology US, LLC (GTC) today announced that it has joined Fractionation Research Inc. (FRI), a non-profit research consortium that independently tests commercial scale distillation equipment. FRI has put together a strong coalition of over 60 members including fortune 500 companies, linking suppliers and buyers together while promoting best practices in the industry. GTC intends to conduct tests at FRI and allow members to vigorously evaluate GTC Process Equipment Technology product lines. FRI will play an essential role in providing unbiased assessments of GTC’s products, offering clients a deeper understanding of product performance and function. “FRI is one of the most respected non-profit organizations in the industry and an influential voice in efforts to promote best practices and improve fractionation devices. Joining FRI further demonstrates our commitment to quality products and ultimately better value for our...

Manager, Energy Services

Mon, 05 Mar 2012 06:00:00 GMT

Title: Manager, Energy Services Description: Description: Headquartered in Houston, TX, GTC Technology US, LLC is a global licensor of process technologies, offering engineering services, process equipment solutions, chemicals and catalysts to the chemical, petrochemical refining and gas processing markets. Our people are our greatest asset: we strive to create a culture that provides challenge, fun and balance. Job Title: Manager, Energy Services Summary: Responsible for executing the strategic business plan and ensuring the delivery of sales and financial goals within the Energy Services business unit by directing GTC sales and execution team activities. Essential Duties and Responsibilities include the following: Meet or exceed gross margin sales goals through development of target market segment strategies Assess market conditions, forecast, plan and show leadership to drive both short and long...

Conferences

Fri, 04 May 2012 15:03:19 GMT

International Downstream Technology & Stategy Conference (IDTC)
21-22 May 2012, Rome

Dr. Matt Thundyil, GTC Manager - Sulfur Business, will present "GT-SPOC: A Novel Approach to Claus Sulfur Recovery".

International Refining and Petrochemical Conference (IRPC)
12-14 June 2012, Milan

Dr. Matt Thundyil, GTC Manager - Sulfur Business, will present "The Ultimate Path to H2S-Free Gas".

Sulphur & Sulphuric Acid 2012, China International Conference and Exhibition
20-22 June 2012, Shanghai

Dr. Matt Thundyil, GTC Manager - Sulfur Business, will present "GT-SPOC: A Novel Approach to Claus Sulfur Recovery".

Office Locations

Wed, 07 Mar 2012 17:18:46 GMT

Houston, Texas - Headquarters GTC Technology US, LLC 1001 S. Dairy Ashford, Suite 500 Houston, Texas 77077 USA Main: +1-281-597-4800 Fax: +1-281-597-0942 Toll Free: +1-877-693-4222 Directions to our office in Houston Bozeman, Montana GTC Research and Development 910 Technology Boulevard, Suite F Bozeman, Montana 59718 USA Main: +1-406-582-7417 Fax: +1-406-922-6440 Dallas, Texas GTC Process Equipment Technology 1333 Corporate Drive, Suite 320 Irving, Texas 75038 USA Main: +1-972-887-3802 Fax: +1-972-887-3826 China GTC (Beijing) Technology Inc. Room 2801 Building C of...

** Home Page - Featured Content

Fri, 17 Feb 2012 22:58:20 GMT

Global Technology Licensor

GTC Technology is a global licensor

of process technologies, offering engineering services, process

equipment solutions, chemicals
and catalysts to the chemical, petrochemical, refining and gas processing markets.

GTC's Sulfur and Gas Processing Technology Portfolio

Fri, 06 Jan 2012 20:36:52 GMT

GTC's gas processing and sulfur technology portfolio is focused on delivering eco-friendly solutions for acid gas removal, dehydration, mercury removal, liquids recovery and sulfur recovery from a variety of process gas streams to meet very specific customer needs. These technologies are delivered in a variety of ways including license with a basic engineering package or with an Engineering, Procurement and Contruction management (EPCm) package. Our broad portfolio of products and extensive experience enables clients to seamlessly integrate our processes across business lines. Listed below is an overview of our gas processing and sulfur removal technologies offered. GTC has a large and varied portfolio of technologies for the removal of contaminants and the recovery of sulfur and CO2 from a variety of process streams. We utilize these technologies to deliver robust and reliable custom solutions for challenging applications across a variety of industries. Sulfur...

Sour Water Stripper GT-SWS

Thu, 22 Dec 2011 22:36:36 GMT

GT-SWS™ is a process designed to remove H2S and NH3 from sour water. Sour water can be generated in a variety of ways in a refinery and a petrochemical plant. Effectively and robustly stripping H2S and NH3 either together or separately is an essential operation. Innovations in mass transfer and contaminant control improve overall energy efficiency. Process Description The sour water is generally fed to a sour water storage tank to help separate hydrocarbons and enable feed mixing to stabilize the feed composition to the stripper unit. Sour water from tankage is heated by hot stripped sour water and fed to the sour water stripper. Heat is added to the stripper either directly (live steam) or through a steam driven reboiler. H2S and NH3 rise to the top of the stripper column where they are removed. Stripped sour water leaves as the tower bottoms and suitable for reuse in the plant, or sent for further waste water processing. In the case of systems where the H2S and NH3...

GT-MeriSorb Acid Gas Removal and Acid Gas Enrichment

Thu, 22 Dec 2011 22:34:51 GMT

GT-MeriSorb is a solvent based technology to capture acid gases by absorption followed by regeneration. Optimized solvent chemistry is critical to manage amine degradation and operation in the presence of heavy hydrocarbons, heat stable salts, and oxygen. Innovations in mass and heat transfer improve overall energy efficiency. Process Description Gas containing H2S and CO2 is contacted in an absorption tower with a solvent which has a preferential affinity for the acid gas. This allows the feed gas to be stripped out of these components which end up in the solvent. The purified gas leaves at the top of the absorber tower. The rich solvent is then heated through the lean-rich exchanger, and sent to the stripper column where it is thermally stripped. The lean solvent is re-circulated, cooled through the lean rich exchanger and then through fin-fan or other coolers prior to entering the amine absorber. For acid gas enrichment, the solvent is chosen to have a preference for...

Sulfur Recovery - GT-Claus Modified Claus Sulfur Recovery

Thu, 22 Dec 2011 22:28:59 GMT

GT-Claus™ is a modified Claus technology. GTC Technology, in alliance with Rameshni and Associates (RATE) and Shandong Sunway, is able to offer highly customized solutions for sulfur recovery across a range of industries and streams recovering sulfur in the 3 - 2,500 Ton/day range. Process Description The GT-Claus™ modified Claus process has a thermal (combustion) section that partially converts H2S to SO2, followed by combustion and catalytic sections that react the H2S and SO2 to recover sulfur. The gas exits the thermal section, enters a waste heat boiler where heat is recovered. Sulfur is then condensed and the unreacted gases are reheated before introduction to a Claus catalyst bed. Following the catalyst bed, the sulfur is again condensed out before repeating the reheat, catalyst bed stages again. Overall sulfur recovery depends on the number of stages, and can reach 98%. GTC can customize the configuration fo the GT-Claus unit depending on the acid gas...

Hydrogen Sulfide Removal Technology - CrystaSulf

Thu, 22 Dec 2011 22:17:22 GMT

GTC Technology, in alliance with CrystaTech, is supporting projects utilizing CrystaSulf technology, a nonaqueous process that has been developed specifically for the treatment of high-pressure sour natural gas in medium-sized sulfur applications with produced sulfur in the range of 0.1 to 30 tons per day. Process Description CrystaSulf uses a nonaqueous solution with a high solubility for elemental sulfur. Because the elemental sulfur stays dissolved in the solution, there are no solids in the liquid circulated to the absorber. By design, CrystaSulf avoids the problems that make the aqueous sulfur recovery systems unsuitable for direct treatment of high-pressure sour gas. With this process, H2S is removed from the sour gas in a conventional tray absorber. The H2S reacts with dissolved sulfur dioxide (SO2) to produce dissolved elemental sulfur. There are no solids in the absorber, flash tank, or solution lines, which minimizes the chance of plugging. Rich...

Sulfur Recovery - GT-DOS Direct Oxidation to Sulfur

Thu, 22 Dec 2011 22:15:28 GMT

GT-DOS™ is a patented technology developed by TDA Research and licensed worldwide by GTC Technology. GT-DOS™ offers simplicity of operation, and is specifically applicable to lean acid gas streams, cost effectively recovering sulfur in the 0.1 to 200 Ton/day range. Process Description The GT-DOS™ technology converts H2S catalytically directly into sulfur, from lean (low concentration) H2S streams. The sulfur conversion efficiency is around 90% in a single pass. H2S + ½ O2 -> S + H2O The H2S containing feed stream is mixed with air and heated to the reaction temperature and fed to the GT-DOS™ reactor. The mixed metal oxide catalyst has been proven to be resistant to high concentrations of hydrocarbons, including aromatics and olefins. The reacted stream containing sulfur vapor is condensed to recover the sulfur. The gas stream can be further desulfurized with sorbents or tail gas treatment. Heat integration between the...

Aromatics Recovery Technology - GT-BTX

Thu, 15 Sep 2011 15:28:44 GMT

GT-BTX SelectSM is GTC's premier aromatics recovery technology. GT-BTX Select uses extractive distillation (ED) to purify benzene, toluene, and xylene (BTX) from refinery or petrochemical aromatics streams such as catalytic reformate or pyrolysis gasoline. The process is superior to conventional liquid-liquid extraction and other extraction processes in terms of lower capital and operating costs, simplicity of operation, range of feedstock, and solvent performance. GT-BTX Select is the most reliable method for grassroots aromatics extraction units and has been applied in revamping all of the established LLE or ED technologies. GT-BTX Select is unique in its ability to extract high purity aromatics with nearly complete recovery from 3-carbon boiling range feedstock. This technology is also the optimum choice to meet the gasoline specifications of reduced benzene. Process Description In our GT-BTX aromatics recovery technology, hydrocarbon feed is preheated with hot...

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noemail@gtctech.com — Thu, 10 Jan 2008 23:05:04 GMT

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Release Date: 10-Jan-08 5:05 PM
Expiration Date: 10-Apr-08 5:05 PM

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2008-01-10T23:05:04Z

Instructor: Instructor

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