Low cost revamp to process heavy sour crudes

A significant improvement in refining margin can be achieved through a low
to moderate cost revamp to enable processing of heavy sour crudes

CHIRANJIB HALDAR and TANMAY TARAPHDAR
Technip India

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Article Summary

Refineries worldwide are facing the challenge of shrinking margin. Many refineries in western countries have shut their operations in recent years. Low crude oil prices vis-à-vis low product prices have worsened the situation, hence refiners are looking for ways to improve refining margin. Processing heavy sour crudes, which are available at a price discount, is one of the options to improve refining margin. If we look at the world’s crude reserves (see Figure 1), heavy sour crude alone constitutes about 18% of the total. Generally, these heavy sour crudes are available at a price discount because of their processing difficulties.

If we analyse future demand from the product side, Figure 2 indicates a trend of higher growth in demand for diesel compared to gasoline. Growth in diesel is expected to be almost three times that of gasoline, a trend that is also currently evident. It may be advantageous for refiners to process some of the heavy sour crudes with more gasoil yield than naphtha to satisfy increased future demand for diesel. However, there are several challenges associated with processing heavy sour crudes and they need to be addressed properly.

What are the challenges?

Heavy sour crudes are highly viscous; they contain high sulphur, high salt and metals. Some heavy sour crudes also contain high naphthenic acid. There are several key areas that must be addressed in the crude and vacuum unit design when feeding these crudes. The situation also affects downstream hydroprocessing and secondary conversion units. Some of the major issues are discussed below.

Asphaltene precipitation: it is important to check the compatibility of selected heavy crudes with the existing crude blend to avoid any asphaltene precipitation. Asphaltene precipitation can cause plugging of heat exchanger tubes and piping.
Hydraulics: plant hydraulics need to be rechecked for handling heavy crudes due to the high viscosities involved. Booster pumps may have to be added to compensate for high pressure drop.
Preheat exchangers: high viscosity will cause higher pressure drop and low heat transfer coefficient in the preheat exchangers. There is also a higher chance of fouling. New heat exchangers need to be added, or some improvement in existing exchangers can be made with a helical baffle or twisted tube design.
Poor desalting: desalter performance can be significantly reduced due to higher salt content and high density and viscosity, which leads to more stable emulsion formation. Poor desalter performance will cause high oil entrainment in brine as well as excess salt content and basic sediment and water (BS&W) at the desalter outlet, which will subsequently lead to rapid corrosion in the crude column overhead. High chloride content in the vacuum diesel/light vacuum gasoil (LVGO) cut is frequently experienced in refineries processing heavy sour crudes. Unless operating conditions (desalter temperature) may be adjusted to cope with the crude’s properties, the existing desalter system may need to be enlarged or replaced with a new and improved desalting technology.
Furnace coking: heavy sour crudes have a higher inclination for cracking and hence there is a higher chance of coke formation in the crude and vacuum heater furnaces. Coking can be minimised with a higher amount of velocity steam as well as reducing the heater heat flux. A higher amount of stripping steam may also be added in the crude and vacuum column to reduce the furnace outlet temperature for the same cut point of products. However, higher steam injection may be limited by the hydraulic capacity of trays or packing, by column diameter, or by overhead condensing/ vacuum ejector system capacity.
Column limitation: if any cut in heavy crude, such as atmospheric or vacuum gasoil, has a much higher yield in comparison to conventional crudes, it could affect the loads in the corresponding fractionation or pumparound sections of the column. Because they have higher yields of residues, achieving similar atmospheric and vacuum gasoil recovery when processing heavy crudes is challenging compared to light or medium crude processing. Debottlenecking columns (heat exchange zones and fractionation zones including wash zone) and design changes are required to recover these higher gasoil yields from heavy crudes. Constraints and impacts on heat recovery trains and energy efficiency also need to be assessed.
Higher corrosion: heavy crudes containing high sulphur and high naphthenic acid will cause higher levels of corrosion. This is generally referred to as high temperature sulphidic corrosion and naphthenic acid corrosion. The corrosion rate depends on sulphur and naphthenic acid concentration, temperature, flow characteristics, H2S content, and so on. Metallurgy with a higher molybdenum content (SS317L or better alloys with ≥3% molybdenum) improves resistance to naphthenic acid corrosion, while higher chromium content increases resistance to sulphidic corrosion. If the existing metallurgy is not suitable for selected heavy crudes, metallurgy upgrades are needed, particularly in the hot portion of the crude preheat, the gasoil circuit, the atmospheric and vacuum residue circuit, and in the column internals. Other systems need to be checked, based in particular on naphthenic acid distribution in the crude being processed.
Impact on vacuum gasoil (VGO) feedstock quality to downstream conversion unit: vacuum gasoil is generally processed in a downstream conversion unit, either a fluid catalytic cracking (FCC) unit or hydrocracker (HCU). Heavy crudes may produce VGO feedstocks with increased sulphur and nitrogen, exceeding the acceptable limit of the downstream catalytic system. Heavy metal and Conradson carbon content will lead to catalyst poisoning and reduced unit conversion or cycle length. Control of the metals and Conradson carbon content of the VGO stream should be carefully reviewed when checking the adequacy of the vacuum distillation unit for processing heavy crudes. In the case of a FCC unit, treatment of the feed in a VGO hydrotreater may be required to reduce the sulphur level, depending upon the overall refinery scheme and product specifications.
Effect on hydrotreaters: almost all petroleum products need hydrotreatment to meet stringent environmental regulations. Proces-sing heavy crudes containing more sulphur, nitrogen, metals, and aromatics has a significant impact on hydrotreaters. These higher impurities call for stringent operating conditions, leading to reduction of catalyst life for the same product specification. Moreover, heavy crudes have a high VGO content, which increases the hydrotreater feed. Revamping existing hydrotreaters may alleviate this problem. Optimum and cost effective solutions are widely case dependent and may include a review of catalyst selection; increase of make-up and/or hydrogen recycle purity; addition of one hydrotreating reaction section to an existing hydrotreater, potentially at a higher pressure; and segregation of gasoil streams from distillation and conversion units in order to optimise the performance of a combination of low pressure and high pressure hydroprocessing units while meeting the pool specifications. The flow rate of the reactor effluent wash water also needs to be increased for washing additional ammonium salts in www.eptq.com Revamps 2015 3 order to minimise corrosion. The amine loading of scrubbers needs to be increased to address additional sulphur, keeping the amine flow rate unchanged. Another concern can be the suitability of metallurgy for naphthenic acid corrosion at high temperatures. However, it has been found that if the oil is mixed with hydrogen before heating to a higher temperature there is less chance of naphthenic acid attack for 300 series stainless steels, even with low molybdenum content.
Increased hydrogen requirement: the higher level of hydrotreatment required for processing heavy sour crudes will require more hydrogen. The hydrogen generation capacity of an existing refinery can be increased in two ways:
Hydrogen management: depending on the refinery configuration, 5-7 wt% of crude feed ends up as refinery off-gas. The majority of refiners burn refinery off-gas as a low value fuel in the process heaters. The hydrogen potential in some of the streams contributing to fuel gas may be high. This hydrogen, if recovered, can have reasonable economic benefits compared to the production of hydrogen from standalone plants. Moreover, it will reduce the size of an on-purpose hydrogen generation unit. Hydrogen recovery can be achieved by developing a hydrogen balance model across the refinery, identifying the constraints/flexibility of hydrogen usage, and hydrogen pinch analysis for possible alternatives of hydrogen reuse from off-gases. However, recovering hydrogen from off-gas/ refinery fuel gas will also reduce available refinery off-gas. Hence, a careful evaluation of the entire hydrogen and fuel system (including external make-up, if any) is required before implementing any hydrogen recovery project.
Revamp of existing hydrogen generation unit: about 25-30% of additional hydrogen can be generated by a revamp of an existing hydrogen generation unit. Various technology options are available for this purpose. Technip’s Parallel Reformer (TPR) allows about 25-30% of additional hydrogen generation by utilising an unfired reforming module in parallel to the reformer furnace, thereby limiting the cost of additional hydrogen production.
Higher sulphur removal: heavy crudes with higher sulphur content require higher sulphur removal capability. The sulphur block of the refinery, including the amine wash/ amine regeneration unit, sour water stripping, fuel gas treatment, sulphur recovery and tail gas treatment unit, may need a revamp or additional equipment. Increased sulphur removal can be achieved in existing sulphur recovery units by implementing oxygen enrichment technology. The basis of the technology lies in removing all or part of the nitrogen typically carried in combustion air and replacing it with oxygen. This allows an additional volume of acid gas to be processed for the same unit pressure drop across the plant. Nitrogen present in the combustion air plays no part in Claus reactions and acts as an inert gas that is carried through the process. Some of the heat generated in the combustion reaction heats the nitrogen present in the process gas, thereby lowering the bulk temperature in the furnace and wasting energy. An increase in oxygen concentration of up to 28%, which does not require any major modification to existing equipment, can increase the capacity of sulphur recovery units by 20-25%, higher oxygen concentrations providing the ability to further increase sulphur recovery capacity. Oxygen-enriched air may be derived from the refinery nitrogen generation unit.

Figure 3 shows the impacts of processing heavy sour crudes in a typical refinery. Depending on the selected crudes, most of the units are expected to be affected.

The biggest challenge in processing heavy sour crudes lies in handling the bottom of the barrel. It is important to have a robust and reliable bottom of the barrel processing scheme to derive full benefit from processing heavy crudes. The bottom of the barrel scheme may include several units to make it robust. Various bottom of the barrel processing technologies with their pros and cons are discussed briefly in the following.

Selecting bottom of the barrel processing technologies

Processing heavy crudes significantly increases the amount of residue. Moreover, this residue will have a much higher amount of impurities such as sulphur, nitrogen, metals and CCR. Conversion of this residue to more valuable middle distillate requires suitable bottom of the barrel processing technology. Several technologies are available, including visbreaking, coking (delayed coking, fluid coking), solvent deasphalting, resid fluid catalytic cracking (RFCC), fixed bed hydrocracking, ebullated bed hydrocracking, slurry phase hydrocracking and gasification. Each of these processes has its own merits and demerits and selection of the optimum process depends on many factors such as existing refinery configuration, specific product slate desired, feed and product pricing, and types of crudes available. Prudent selection of heavy sour crudes together with an appropriate bottom of the barrel upgrading process or a combination of bottom of the barrel processes can increase the refinery margin significantly. Brief accounts of these technologies follow.

Visbreaking

A visbreaker thermally cracks large hydrocarbon molecules in residue by heating them in a furnace at 450-500°C to reduce viscosity, producing small quantities of light hydrocarbons, LPG and gasoline. The severity of visbreaker operation is normally limited by the stability requirements of fuel oil, which is the major product of the visbreaking unit. It can be applied to atmospheric residue, vacuum residue and even solvent deasphalter pitch. However, visbreaking cannot be considered a good processing option for the current product trend of minimum or zero fuel oil production.

Solvent deasphalting

Solvent deasphalting (SDA) is a physical process to separate asphaltenes from residue using suitable paraffinic solvents (propane/butane/pentane, depending on the technology). The process produces low contaminant deasphalted oil (DAO) that is rich in paraffin molecules. The deasphalted oil (DAO) can be used as feedstock for fluid catalytic cracker or hydrocracker units due to its low metal content. The main disadvantage is utilisation of SDA pitch. If a delayed coker is available, the pitch may be sent to the coker for final conversion and recovery of the remaining oil value. Pitch has also been used commercially as feedstock for gasification and hydrogen production. Hence SDA alone cannot be considered a good processing option; it should be combined with some other bottom of the barrel processing technology.

Coking (delayed coking or fluidised bed coking)

Delayed coking has been selected by many reï¬ners as their preferred choice for bottom of the barrel upgrading, because of the process’s inherent ï¬‚exibility to handle any type of residue and its zero production of fuel oil. About one-third of installed residue upgrading plants are based on delayed coking. It cracks hydrocarbons at high temperature (500-530°C). The process provides essentially complete rejection of metals and carbon while providing partial conversion to high value liquid products (naphtha and diesel). The foremost disadvantage of this process is high coke formation, almost directly proportional to the Conradson carbon residue of the feed, and its low yield of liquid products.

Fluid coking and ï¬‚exicoking are ï¬‚uid bed processes developed from FCC technology. Fluid coking can have liquid yield credits over delayed coking. Flexicoking is an extended form of ï¬‚uid coking and uses a coke gasiï¬er to convert excess coke to syngas.

Resid fluid catalytic cracking (RFCC)

RFCC is an extension of conventional FCC technology, which offers better selectivity to high gasoline and lower gas yield than hydroprocessing and thermal processes. This process cannot be used for maximisation of diesel. The major limitation of RFCC is the need for good quality feedstock (high hydrogen/carbon ratio and low metal content). Typically RFCC can operate with feedstock containing 6-8 wt% CCR and about 50 ppm metals (Ni+V). Hence a feed pretreatment process such as atmospheric or vacuum residuum desulphurisation (ARDS/ VRDS) unit is required. Technip’s RFCC technology is a versatile technology that offers higher propylene and gasoline yield.

Hydrocracking

Fixed bed hydrocracking may be preferred if the amount of CCR and metals in the residue is low. The process converts heavy oil using catalyst and H2 in a reactor at high temperature and high pressure. Resid conversion is 25-45% in a fixed bed reactor. Ebullated or moving bed hydrocracking can achieve 65-75% conversion. It uses a catalyst similar to fixed bed hydrocracking, but the catalyst is added and removed while the unit is in operation. Ebullated bed processes can use heavy feed residues with elevated sulphur, nitrogen and metals content and do not require pretreatment. These processes have higher liquid yield compared to fixed bed hydrocracking. However, the balance of the residue needs to be processed separately.

Slurry phase hydrocracking is an emerging technology that promises a higher liquid yield. However, there are very few commercial references to date.

Gasiï¬cation

This process involves complete cracking of residue (coke, asphalt) into gaseous products. The gasiï¬cation of residue is carried out at high temperature (>1000°C), producing syngas, carbon black and ash as major products. Integrated gasiï¬cation combined cycle (IGCC) is an alternative process for heavy residue conversion and is an emerging technology for efficient power generation with minimum effect on the environment (low SOx and NOx).

To date, delayed coking is the predominant option for bottoms processing. Hence the delayed coking option has been chosen for the following case study. Case study This study uses linear program (LP) modelling to analyse changes in distillate yield and gross refinery margin (GRM) when processing heavy sour crudes in a refinery of 300000 b/d (15 million t/y) capacity.

The base case refinery consists of a CDU/VDU as the primary unit, a catalytic reforming unit and isomerisation for gasoline production, an FCC unit and full conversion hydrocracker unit as secondary units. A delayed coker unit (DCU) is also considered as a bottom of the barrel processing unit in order to mitigate fuel oil production and increase distillate yield. Hydrotreating of all products such as kerosene, diesel, naphtha and VGO is considered to meet product specifications and environmental regulations as well as to meet feed specification for downstream units, as applicable. A block flow diagram for the base case refinery configuration is shown in Figure 4. The LP model was developed based on this configuration with maximisation of GRM as the objective on the following basis:

Capacity: 15 million t/y (300 000 b/d)
Crude: 50% Arab Heavy and 50% Arab Light
Gasoline and diesel as per Euro-IV specification
Zero fuel oil production.

Alternative crude blends

Two heavy crudes, Maya and Duri, are introduced in the existing refinery, keeping the total refinery throughput the same as in the base case. Duri is not only a heavier crude but also has a high total acid number (TAN). The amount of this high TAN Duri crude feed is limited to keep the TAN of blended crude below 0.5, in order to avoid major material change. The amount of Maya crude is limited in such a way that the total amount of heavy crude does not exceed 80% of throughput, so that loading at the crude column top section is above the design turndown value of 50%. The API gravity, sulphur content and TAN number of these crudes are shown in Table 1. The combinations of crudes considered for the case study are described below and summarised in Table 2:

25% Arab Light, 25% Arab Heavy, 25% Maya and 25% Duri crude (50% existing crudes and 50% heavier crudes)
20% Arab Light, 20% Arab Heavy, 35% Maya and 25% Duri crude (heavy crudes increased to 60%)
20% Arab Light, 50% Maya and 30% Duri crude, (no Arab Heavy and only 20% light crude).

Analysis and results The distillate yields of each of these cases are shown in Table 3 and Figure 5. It is evident that distillate yield decreases slightly with a reduction in light crude feed; however, the yield of diesel increases with higher levels of heavier crude feeds. Likewise, the percentage of diesel in the distillate has increased significantly with higher throughput of heavier crudes. The GRM also improves significantly with higher levels of heavy crude feed. Moreover, the diesel to gasoline ratio is enhanced considerably with heavier crudes. The comparison of GRM and diesel to gasoline ratio for different blends is shown in Table 4 and Figures 6 and 7.

Revamp requirements

All of the results of the case study clearly indicate that the profitability of an existing refinery can be enhanced significantly when processing more heavy crudes. However, this increase in profitability is associated with capital investment. As these crudes are heavier than conventional crudes, the loadings at the crude column bottom section and vacuum column are increased substantially. Moreover, the throughput for a downstream delayed coker unit and hydrocracker also increases considerably due to the resulting higher residue and gas oil content. As a result, debottlenecking of these existing units is mandatory. Table 5 indicates the effect on unit capacities for processing different blends of heavy sour crudes. It is evident that for Blend 3, with almost 30% additional GRM, there is a requirement for about 27-30% capacity increment for the VDU and hydrocracker. This can be achieved with a low to moderate cost revamp. However, for the delayed coker unit, the required capacity enhancement is about 56% and hence the unit requires additional coke drums and heaters with a major revamp of the downstream fractionation section. Considering the significant gain in GRM, the capital investment required for these debottlenecking operations can be justified. Generally, payback is within an acceptable period by industry standards.

Although there is an almost 30% increase in GRM for Blend 3, the light end processing units such as the naphtha hydrotreater, kerosene hydrotreater, reformer and isomeriser are under-loaded with respect to their original design capacity, especially in comparison with Blend 1 or Blend 2. Hence, instead of opting for Blend 3, it may be better to proceed with Blend 2 with 10% additional throughput, which will not only ensure better utilisation of existing units but will also result in further improvement of annual GRM. Besides the aforesaid revamp requirements, a very low cost revamp of the existing CDU, DHT and FCC unit will also be required for this case as their capacities are augmented to nearly 110%. Comparisons of annual GRM and unit capacities for Blend 2 with 100% and 110% capacities, and for Blend 3 with 100% capacity, are provided in Tables 6 and 7, respectively.

The optimum crude blends (the proportion of heavy crudes that will enable an increase in GRM given the limitations of the existing units) could be further determined through a preliminary cost-benefit analysis, taking into account the estimated ultimate capacity of all the existing key equipment for the units to be revamped. Such analysis would lead to identification of low to moderate cost revamp scenarios, corresponding to a limit of heavy sour crude content in the crude blend. Some typical major revamp options are:

Achieving the maximum revamp capacity of the VDU by considering high capacity packing and low cost revamp options for the VDU furnace after additional heat recovery from vacuum residue and VGO rundown as well as pumparounds.
Optimisation of the catalytic volume of the hydrocracker for a given reactor size and recycle compressor ultimate capacity. For example, if a scheme is initially selected with some recycle for the hydrocracker, one debottlenecking option could be to decrease recycle and conversion and increase unconverted oil to the FCC, thus ‘balancing’ the capacity increase between the hydrocracker and the FCC unit.
Achieving maximum revamp capacity of the delayed coker main fractionator by upgrading the column internals and achieving the ultimate capacity of the wet gas compressor after modifications such as use of a spare wheel, increasing speed, considering turbine drive, and so on.

It is evident from this case study, that a significant improvement in GRM can be achieved by a low to moderate cost revamp to process heavy sour crudes. This will require major debottlenecking of the hydrocracker and DCU along with a moderate revamp of the VDU. Minor modifications may be required for the CDU, FCC unit and diesel hydrotreater. Alternatively, the proportion of heavy sour crude that can be processed in an existing refinery may be fixed to an intermediate level between those evaluated, based on the extent of revamp required in units like the coker.

Conclusion

Crudes selected for the case study are for comparison purposes only. A strategy is required for an upgrade to enable a refinery to process a wide range of heavy and sour crudes. The ultimate goal of the revamp is to achieve sustained and reliable post-revamp operation to convert low value heavy sour crudes into high value refined products. Technip’s experience in revamping as a licensor (for FCC, hydrogen generation and open art units), as feasibility study and FEED consultant, and as EPC contractor reveals that a deep understanding of process, equipment, metallurgy and operating safety are required to make the revamp successful. A strong EPC knowledge is also essential to execute the revamp job within an aggressive schedule by minimising the turndown period, thus enhancing profitability.

References