Mega-olefin plant design: Reality now Bigger is better, when planning future ethylene processing capacity

C. P. Bowen and D. F. Jones, Shaw Energy & Chemicals, Houston, Texas

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The olefin industry continues to expand and upgrade its capacity and equipment. Present olefin-plant capacities, investment costs, equipment delivery schedules and construction timetables represent many of the industry's major challenges. These concerns were true in the late 1990s when the largest cracking furnaces (ethane and naphtha types) were constructed, and when the largest total plant capacities approached 1,500,000 tpy (1.5 MMtpy).

As current projects, prices and participants have extended plant sizes and upstream/downstream links, these challenges must be addressed in conjunction with key equipment manufacturers. Ongoing design of key equipment corresponds to respective nominal naphtha/ethane cracking capacities of 1.5 MMtpy to 2 MMtpy for future ethylene plant designs.

Market trends. Olefin production capacity has virtually doubled in the past 15 years. Current capacity is approximately 130 MMtpy and demand is about 114 MMtpy. Global ethylene growth rate is still approximately 4.5%/yr, and processing capacity is forecast to double again by 2025. Various alternative production routes to ethylene/propylene have been recently proposed, but the bulk of new production will still come from conventional steam crackers.

Corresponding plant capacity projections. As a consequence to the total olefin growth rate during the past generation, steam cracker maximum capacities have increased from 0.5 MMtpy ethylene (late 1970s) to 1.5 MMtpy today. At present, there are over 30 units with 1+ MMtpy of processing capability in service or under construction. The industry has correspondingly increased individual equipment item sizes, and, in anticipation of even larger plant capacities, is now developing even larger key equipment items.

The steam-cracking industry is not unique in this trend. Refinery units have doubled during the same time frame (200 Mbpd to 400 Mbpd); petrochemical derivative units have also increased unit size by a similar factor as per ethylene units.

Investment cost vs. capacity. A standard relationship between investment and plant capacity for most olefin units is linked to a factor ranging from 0.65 to 0.85. Accordingly, larger olefin units can generate higher cost production margins. But this involves several investment concerns including equipment and operational reliability, availability of essential feedstocks and adequate product disposal.

Feedstock, energy and chemical plant investment costs have significantly increased during the last five years. At the turn of the century, the reference cost for a standard naphtha-cracking ethylene plant was ±$1,000/ton ethylene per year. At present, that cost is 40% higher due to the higher cost of basic and specialty materials, increasing fabrication sales costs, construction team availability and general engineering costs. So, the combination of higher unit costs offset by investment costs vs. capacity factors further encourages the olefins industry to move to higher capacity facilities.

Fig. 1 Current mega-plants incorporate significantly higher cracking furnace capacities and performance flexibility.

Equipment size trends. The industry has responded well to the increasing plant capacity demands and improved operational efficiency. Accordingly, equipment disposition and item count within today's olefin units is actually less than it was a generation before. New plant designs have increased specific capacities of key items significantly. Newer olefin facilities have integrated several heat and mass transfer facilities, combined various equipment vessels, expanded catalytic reactor capacities, extended heat pump links between standard compressors and fractionators, and significantly increased key equipment duties/capacities. Specific data related to key olefin equipment items will be further discussed.

Cracking furnaces. Early smaller ethylene plants often contained up to 20 individual cracking furnaces. For example, a major European unit, constructed 35 years ago, had an initial processing capacity of 450 Mtpy and used 16 fresh-feed furnaces plus two recycle furnaces. Today, the standard liquid-feed furnace sizes are seven times larger. Gas-feed cracking furnaces produce even higher ethylene yield outputs.

The latest designs for liquids-cracking furnaces use symmetrical U-type radiant coils; thus, furnace capacities have increased by up to 25% within identical radiant firebox dimensions. One of the largest naphtha-cracking furnaces currently under construction will produce 190 Mtpy of ethylene. Key design features in this unit are:

• Dual radiant cell design (each cell contains 112 U-type coils) • Total radiant firebox floor firing with relatively large low-NOx burners • Radiant cells may be separately decoked; decoking effluent directed into radiant firebox

to minimize decoke effluent contaminants • Multi-pass convection section including slot for future SCR—selective NOx catalytic

reduction • Variable RPM induced flue gas fan to optimize combustion conditions during

startup/decoke/turn-down • Modular system design-fabrication of entire furnace to facilitate construction phase • Individual double-tube selective linear exchangers (SLEs) are directly connected to

each radiant coil outlet; total quench heat recovery is achieved in each SLE per each unit.

• For heavy feedstocks, the cracked effluent is cooled to at higher temperature and is subsequently directly quenched with quench oil to reduce main transfer line operating temperatures

• Multi-stage startup/shutdown control facilities provide necessary uniform operations and avoid equipment damage due to emergency conditions

• The 190-Mtpy U furnace consumes about 200 MW fuel and generates 100 metric tons/hr super high-pressure (SHP) steam

• Operating run length for such furnaces is typically about 45 days.

Representative cracking furnace capacities are listed in Fig. 2.

Fig. 2 Recent North American mega-furnace designs.

Main train compressors. Virtually all ethylene plants today incorporate a single cracked-gas compression system. Earlier units sometimes used twin parallel units or even a spare unit. Some units prior to 1970 consisted of multiple reciprocating compressors. High-capacity centrifugal compressors represent many design, fabrication and operational challenges. Today, there are few compressor manufacturers who can meet mega-capacity requirements. Recent design extensions and definitions include:

• Naphtha-type cracking requires low suction pressures (0.17 barg– 0.30 barg) to optimize cracking selectivity. Discharge pressure is typically about 35 barg to permit downstream condensation of methane vs. ethylene refrigerant. Maximum interstage discharge temperatures should ideally not exceed 90°C. Accordingly, such system normally requires five stages in series.

• Typical suction volumetric flow for a 1.5-MMtpy ethylene naphtha cracker compressor ranges from 500,000 m3/h to 700,000 m

3/h. The LP body for recent larger scale plants

has either been a large, double flow machine, or, in some plants two parallel flow LP bodies. Typically, the impellers in process Stage 2 (MP body section) are very similar in flow coefficient to each of the double flow impellers in process Stage 1 (double flow LP body or two parallel single flow bodies). Each stage often consists of three impellers. But the diameter and rotating shaft length for the 3D impellers sometimes limit the impeller count for such double flow casings to only two impellers per stage.

• The cracked-gas compressor (CGC) will either consist of three or four casings, depending on capacity and vendor. The three casing arrangement is normally a double flow LP casing for stage one; a single flow MP casing for Stages 2 and 3; and a single flow HP casing for Stages 4 and 5. In some cases, vendors have selected four compressor bodies, two parallel flow LP bodies for Stage 1 and the MP and HP bodies similar to the three body arrangement described previously.

• Client input is required during the selection of the first-stage compressor flow

coefficient— = f (volume flow, diameter 2, RPM). Long-term plans to increase plant

capacity will impact this decision (See Fig. 3). • Client input is also required for train layout considerations. For 1.5-MMtpy-naphtha

crackers, the cracked gas API normal condition can absorb power in the range of 90

MW to 100 MW. Operating two trains in series, LP/MP and HP, respectively, is to be considered. In a single-train arrangement, normally the impeller/diffuser pairs selected for Stages 1 and 2 will operate at optimum efficiency. The performance for Stages 3, 4 and 5 are progressively compromised by the rotational speed dictated by Stages 1 and 2. In mega-plant sizes, the power saved by operating Stages 4 and 5 at a higher optimum speed can be significant.

• Ethane-cracking compressors can be optimally designed for higher suction pressures (~1.3 barg) and slightly lower discharge pressures, and accordingly have only four stages. Ethane cracking yield molecular count is about two whereas naphtha yield is approximately four molecules per feed molecule. Ethane-cracker cryogenic fractionation is essentially ethylene/hydrogen; hence, the demethanizer system pressure is somewhat lower than that of the naphtha generated ethylene/methane/hydrogen system. Accordingly, the ethane-cracker CGC and its upstream quench area system are smaller in terms of both volumetric flow and energy demand.

• For reference purposes, ethane-cracker CGC capacity and power are typically only 75% of that of the equivalent ethylene capacity naphtha cracker. Based on present commercially available designs, the corresponding single compressor/driver maximum capacities are about 1.5-MMtpy ethylene from naphtha and 2 MMtpy ethylene from ethane.

• Client input into the final selection of impeller flow coefficient will impact future uprate potential. It also impacts capital investment (casing size), operating cost (polytropic efficiency at operating flow coefficient relative to peak efficiency flow coefficient) and reliability (impeller stress and/or critical speed margin). For example, very high flow coefficient impellers, bordering on mixed-flow designs, have a significantly higher aspect ratio (axial stage length vs. diameter) than lower flow coefficient designs. Critical speed margin can be compromised by selecting very high flow coefficient impellers. Such high-flow coefficient impellers can also limit train speed based on operating impeller stress.

• Since cracked gas invariably contains concentrations of hydrogen sulfide up to 1,000 ppm, the operating stress limits of the compressor impellers must be lower than that of the equivalent sulfur-free compression condition. Today, essentially all CGC compressors are designed per NACE.

• All critical duty centrifugal compressors are equipped with dry-gas seals. Dry-gas seal systems improve unit reliability and reduce maintenance, such as the avoidance of lube-oil contamination of the cracked gas and refrigerant inventories associated with legacy oil seal systems.

• Continuous clean-water injection facilities are installed for CGC compressor temperature suppression. The vendors have specific limitations on injection rate and water particulate size to minimize erosion while minimizing temperature rise and its resultant positive impact on run length. Many users also install an intermittent wash-oil injection for cleaning. Considering the modest capital required, it is recommended to design and install both systems during construction. As noted, water injection is continuous, except when the oil is injected for cleaning. The frequency for cleaning is site specific and established during operation of the plant.

• Internal coatings of both stationary and rotating elements of the CGC compressor are used by many olefin facilities as a preventive measure to fouling. Such coatings are often re-installed at each plant scheduled turn-around.

• An essential element in verifying the integrity of the compressor system is shop testing, as shown in Fig. 4. Component material verification, testing and dimensional compliance are consistent with current world-scale plant practices. As with the present practice, system energy levels demand section by section compressor thermodynamic performance testing and individual body mechanical testing. The requirement for string testing is user specific.

Fig. 3 Typical centrifugal compressor impeller configuration and efficiency vs. flow coefficient, typical trend for a centrifugal compressor.

Fig. 4 Main train compressor testing at the fabrication shop.

Refrigerant compressors. In ethylene plant design, the respective power demands of the ethylene refrigerant compressor and propylene (or propane) refrigerant compressor are approximately 1/3 and 1/2 of that of the CGC:

• The C2, C3 refrigerant compressor capacities are smaller than that of the cracked-gas machine. Ethylene product export is typically high-pressure ambient vapor. When ethylene users are not available, the plant is often designed for storage, where the product must be exported temporarily as cryogenic liquid. The vapor product condition typically defines the API "Normal" condition for the refrigerant compressors. The intermittent liquid condition often defines the API "Rated" condition. The volumetric differential between these two conditions can be significant, and can drive the API

Normal condition toward surge. Initial compressor impeller/diffuser selection, number of stages (head per stage) and relative Mach number (rotational speed) all impact the compressor stability, and should be evaluated carefully prior to order.

• Depending on the precise recovery scheme design, liquid-ethane-feed cracker C3 refrigerant compressor may have only two or three stages. Naphtha-cracker designs are typically more complex (~ four stages) due to the minimum feedstock refrigeration credit and range of products and co-products.

• Most C2 refrigerant compressors, which are typically combined with C2 fractionation heat pump duty are designed with four stages. In some cases, the C2 refrigerant compressor duty requires five stages, and two compressor bodies.

• The refrigerant compressors are not exposed to component sulfur; therefore, they are not required to be manufactured to NACE requirements. However, the relatively low operating temperatures for these machines require materials of construction that can maintain sufficient ductility throughout the operating range.

• Depending on the plant location and available utilities, some C3 refrigerant compressors use air-cooled C3 condensers. The discharge pressure must be correspondingly higher than water-cooled condenser systems. Final discharge pressure has a second order impact on the selection, and virtually all C3 systems are designed with a single-body C3 compressor.

• Certain of the critical sized equipment related to the refrigerant compression systems are the respective low-temperature plate-fin reboilers/condensers and the refrigerant condensers (Fig. 5).

Fig. 5 Axially split, radial flow inline compressor for olefins refrigeration service.

Steam turbine drivers. Key design criteria include:

• Fixed-rpm steam turbine drivers above 200 MW are currently available. Variable-rpm units, as implemented for ethylene plants, are currently limited to 80 MW. We anticipate that the next-generation steam turbine variable-rpm drivers will shortly be rated at 100-MW capacities.

• Critical-duty drivers are supplied by steam pressures from 100 barg to 300 barg. Ethylene plants are designed to supply steam from 66 barg to 130 barg. Higher

pressure systems are typically more efficient; their steam system operating conditions require very high-quality boiler feedwater (BFW) pre-treatment contaminant removal, de-ionization and de-phlegmation. High-power turbine drivers incorporate various intermediate steam pressure extraction systems. Ethylene plant turbines driving compressors are typically designed as extraction condensing. Normal operating conditions dictate the extraction section design, and startup normally defines the condensing section design.

• Close-cycle ethylene plant steam systems involve relatively high capacity steam turbine condensation fractions. Accordingly, the lowest pressure turbine blades are relatively long and operating speeds often approach blade mechanical design limits. More efficient systems, particularly for high-capacity units, maximize medium/low pressure steam export opportunities and consequently reduce the condensing phase traffic. Consequently, this design reduces the condensing section volume and required blade length, and resultant tip speed and mechanical stress.

• Another operating adjustment involves steam turbine condenser exhaust pressure. During startup or reduced duty operation, the compressor power demand is reduced and, accordingly, the steam exhaust pressure can be higher. The condensation temperature is consequently higher; the flowrate can be higher, and the HP or MP extraction rates can be conveniently reduced. Hence, the turbine blade mechanical tip speed limits can be consequently avoided.

• It is expected that the mega-plant cracked gas and C3 drivers will both operate on the highest pressure steam available within the system. The C2 driver can be designed to operate at the highest (SHP) steam pressure, or possibly an intermediate pressure (HP), depending on location specifics.

• Over the past two decades, advanced steam turbine coatings have been successfully installed in olefin plant applications. The resulting reliability and run-length improvements attributed to steam turbine stationary and rotating coatings warrant evaluation of these options.

• For the 1.5-MMtpy-naphtha crackers or 2-MMtpy-gas crackers referenced, the CGC driver requirement is nominally 100-MW. This condition exceeds the power of steam turbine mechanical drive systems currently operating in the market. Some vendors have completed feasibility and are willing to build 100 MW, single-driver CGC drivers. As noted earlier, compressor power consumption optimization compels the consideration of two drivers. Many other technical factors influence the driver selection including: trip and throttle valve number and size, valve chest references, number of control sections, blade references, etc. Preferred vendor selection, user preference and risk aversion will impact the final decision for one driver vs. two drivers for the cracked-gas train.

Main fractionating towers. Mega-olefin plants include several major towers. Earlier designs often involved semi-tower delivery and in-situ upper/lower section welding. Today, entire towers can be delivered without such construction challenges. A 1-MMtpy naphtha cracker ethylene unit will typically include up to four towers weighing over 1,000 tons. However, freight transport systems adjacent to ports can handle towers of up to 2,000 tons; equivalent major erection facilities can also handle such items.

As plants become larger, the vessel diameters increase on a square root ratio. In certain cases, the diameters and corresponding weight of vessels and towers can be reduced by reducing the reflux ratio and increasing the tray count. Such optimum dimensions apply to the major ethylene and propylene fractionators. Other multi-tower sequences can be adapted to reduce duty, e.g., combination rectifier/stripper towers.

The largest single duty in most naphtha crackers is the C3 fractionator. Its standard reflux ratio may be up to 15:1; thus, both tray count and diameter are extended duties. For reference, a 600-Mtpy polymer-grade propylene fractionator will typically consist of a two series tower system; the respective diameters could be up to 7 m, with 115 m in length and the corresponding weight up to 1,350 tons.

Another major tower is the quench-oil tower. A heavy-naphtha feedstock 1-MMtpy ethylene unit quench tower would be approximately 13 m in diameter and up to 45 m tall. Erection weight for such a unit would exceed 1,100 tons. Fig. 6 shows an example unit.

Fig. 6 The 1,000+ ton quench-oil tower is a key element in this heavy cracking feedstock mega unit.

Ethane or ethane/propane crackers incorporate a quench-water tower in a similar role. That vessel may be of equivalent size/weight to the naphtha-cracker quench-oil tower. But, as mentioned previously, if the ethane cracking coil outlet pressure is elevated (e.g., 1.8 barg vs. 0.6 barg) the downstream quench system and cracked-gas compression system are of reduced physical size. Such a high-pressure ethane cracker producing 1.5 MMtpy of ethylene would incorporate a quench-water tower of only 8.5 m in diameter and 30 m in height with a weight of approximately 500 tons. If however the same plant was based on lower conventional coil outlet pressure, the volumetric cracked gas flowrate would be approximately doubled with a corresponding increase in quench tower diameter and weight.

The other major fractionator tower is the ethylene-ethane splitter. The present current recovery scheme design minimizes the duty on this tower but it is nonetheless of major proportions and weight. A 1.5-MMtpy ethylene fractionator is approximately 7 m in diameter and 60 m in length with a weight of 500 tons.

Major heat exchangers. The largest heat exchangers on many plants are the various air coolers, which can represent up to 50% of the total plant cooling duty. The installed area of such mega plants poses problems. In most cases, the horizontal air coolers will be installed above mega pipe racks—up to 20 m in elevation. Major air coolers will consist of 4–6 rows of up to possibly 20 m in length. Many Middle East plants have restricted seawater usage for cooling, but the ambient-air temperature range forces air coolers to operate at high condensing temperature/pressure. Steam turbine condensers may also be air coolers; these are frequently installed in triangular overhead formats to maximize available duty per unit plot area.

Shell-and-tube heat exchangers have also been extended beyond their traditional dimensions. One of the latest mega plants have incorporated single mega exchangers in high-capacity services such as cracked-gas intercoolers/aftercoolers, refrigerant condensers and fractionator condensers. Such exchangers are up to 2,000 m

2 surface area per shell with single pass tubes

of 13 m in length. Mega units typically relax the delta in temperatures and pressure drops across such exchangers and thereby reduce the surface area and process-side flow dimensions. Key benefits from such designs are linked to the associated piping and installation advantages.

Plate-fin exchangers have also been significantly increased in sizes and capacity as a consequence of mega unit decisions. The manufacturing facilities and techniques have been upgraded so that unit exchangers volumetric size may extend up to 18 m

3 per core and

parallel/series requirements are minimized. Various related improvements have also been incorporated into plate-fin exchangers that directly benefit mega-plant systems, e.g., anti-corrosion metallurgy, upstream protective guard beds, integrated tower reboilers/condensers, etc.

Piping systems. The proportional cost of the piping system in mega plans can be as high as 40% of total investment cost. Incremental cost elements include design, fabrication, associated valving, installation, insulation, testing, pre-commissioning and initial start-up. A major US pipe fabrication company is highly aware of these project elements and has promoted induction heating/bending fabrication techniques to minimize piping bending components and related welding.

Further mega unit features. Operating companies continue to extend capacities on many similar plants. However, we must recognize that the cost:capacity advantage is less pronounced at super high capacities, and various associated feedstock, product, utility, emission aspects pose more difficult operational challenges. Nonetheless, we anticipate continuing plant capacities in the 1-1.5 MMtpy range where key design elements have been successfully achieved. Fig. 7 indicates a recent related mega-capacity unit.

Fig. 7 This recently completed mega-unit was the first joint venture ethylene project and the first unique EPC LSTK unit in China, currently under expansion.

A further similar mega-plant petrochemical-refining joint design philosophy has recently been implemented. Several projects are now under design and construction for Middle East and South American units based on the concept of enhanced fluid catalytic cracking (FCC) schemes linked with conventional ethane and /or naphtha type steam crackers. Later in 2008, a mega plant will start up producing approximately 1.5 MMtpy of ethylene and 1 MMtpy of propylene. Various product recovery facilities and energy supply/demand systems are integrated, and both the FCC unit converter system and steam-cracker equipment items incorporate mega-plant design philosophies. In the role as technology/engineering/construction company, we work closely with operating companies and key equipment manufacturing companies in order to implement effective mega-plant cost/capacity designs of joint benefit to all parties—Bigger is Better. HP

The authors

Colin P. Bowen is the vice president of olefins business development for Shaw's Energy & Chemicals Group (formerly Stone & Webster), where he has worked for approximately 40 years. He is a graduate of Birmingham University and Imperial College, UK. Mr. Bowen is a senior member of AIChE, IChemE and IMechE. He was secretary of AIChE's Fuels & Petrochemicals Division and is Shaw's member on the AIChE Ethylene Producers Committee. He has worked in the global petrochemical industry in a range of contractor positions and has contributed significantly to many ethylene projects during his career.

Daniel Jones is the executive director of furnace technology Shaw's Energy & Chemicals Group (formerly Stone & Webster) in Houston, Texas. Mr. Jones has worked in the petroleum industry for 28 years. His varied experience includes engineered equipment systems for subsea drilling, oil and gas production, gas pipelines, refining and petrochemical applications. His responsibilities have included engineering, marketing, sales and executive management. He is a graduate of the University of Pennsylvania with a BS degree in mechanical engineering.