NG - Fuelling Integration of Refining & Petrochemicals
Tanmay Taraphdar, M K E Prasad, Praveen Yadav, Technip KT India

Refiners, not just in India but across the world, are working towards improving their Gross Refinery Margins (GRM). They are looking for technologies and exploring business dynamics to maximise their profits. This article explores some of the options available for refiners to enhance GRM and reduce carbon footprint with the use of Natural Gas (NG).

Rising oil prices and weak fuel demand in recent past have made a significant impact on GRM. Historical data show that the refineries with bottom of the barrel processing facilities and integrated petrochemicals complex have performed well to stay ahead in the competition due to its greater flexibility to maintain healthy GRM. A robust refinery configuration which is flexible enough to process variety of crudes including difficult opportunity crudes along with integrated petrochemicals complex is the key aspect to sustain healthy margins. However, simple integration with refinery and petrochemicals complex may not be good enough in present scenario. Integration should be smart enough to address volatility of the market by ensuring healthy GRM and to minimise environmental impact by reducing carbon footprint. Use of natural gas as fuel addresses this issue to some extent by allowing recovery of valuable components from refinery off gases and facilitating release of good quantity of naphtha for valuable petrochemicals feedstock generation. It also enables production of more middle distillate from bottom of the barrel processing and helps reducing carbon footprint of overall complex. Price differential between crude and natural gas, especially in the countries where natural gas is available, makes it a hugely profitable proposition. Even for the countries, where both natural gas and crude are imported, it makes a case that needs to be looked into.

Refinery Fuel Consumption and Generation
A refinery consumes fuel gas and fuel oil produced from various refinery processes. No supplementary fuel is required for refinery operation. Generally, naphtha is used as feed and fuel for Hydrogen Generation Unit (HGU) and Gas Turbines (GT). Typically, Process Heaters consume greater amount of fuel, followed by Utilities and Hydrogen Plant.

Fired heaters in various process units consume about 40 to 50 per cent of fuel. Utility system including boilers and GTs consume about 30 to 40 percent of fuel and HGU consumes about 15 to 20 per cent of fuel. Contribution of HGU includes both feed and fuel. Typically, a refinery with secondary processing facilities like Fluid Catalytic Cracking Unit (FCCU) and Hydrocracker Unit (HCU) consumes about 8 to 10 wt% of crude throughput as fuel including naphtha used in HGU and GTs. In case refinery is integrated with petrochemicals complex, which is highly energy consuming, fuel consumption is significantly higher. This fuel requirement is satisfied by fuel oil and fuel gas generated from various process units.

Fuel oil is mainly generated from Vacuum Distillation Unit (VDU) and FCCU main fractionator bottoms in absence of bottom of the barrel processing facilities in the refinery. Vacuum residue is generally taken through visbreaker unit to produce fuel oil. Generation of fuel oil can vary between 5 to 50 percent of feed to VDU depending upon the type of crude processed while fuel oil from FCCU main fractionator bottom can vary between 4 to 6 wt% of FCCU feed.

Fuel gas is generated from all hydrotreating units, MS block (catalytic reforming unit and isomerisation unit), FCCU, Delayed Coker Unit (DCU) and HCU. Crude Distillation Unit (CDU) can also be a source for fuel gas generation if light ends are present in crude. A typical contribution towards fuel gas generation from various process units in terms of wt% of total fuel gas generation are shown in figure 1.

Figure 1 on the previous page shows that DCU, FCCU, MS block (Catalytic Reforming Unit + Isomerisation or Alkylation), CDU (in case light ends are present in crude) and HCU along with hydrotreaters (naphtha, kerosene, diesel and VGO) contribute typically about 30, 15, 18, 19 and 18 percent respectively towards fuel gas generation from refinery. Many modern refineries have integrated petrochemicals complex to improve profitability. Significant amount of fuel gas is generated from naphtha cracker complex while a small amount of fuel gas is generated from aromatics complex (excluding catalytic reforming unit). Typically, about 16-17 wt% of feed is converted into fuel gas in ethane cracker while about 17-18 wt% of feed is converted into fuel gas in naphtha cracker. Fuel oil generation from ethane cracker is negligible while it can be as high as 10 wt% of feed for naphtha cracker. Petrochemicals complex is also a major energy consumer. Steam cracker consumes lot of power in its cracked gas compressors and refrigeration compressors. Typically, 600-620 kWh of power are required for one ton of ethylene production. Generally, naphtha cracker is net exporter of fuel gas and fuel oil while ethane cracker is net consumer of fuel gas. Para-xylene complex is net consumer of fuel gas or fuel oil and power. About 0.3 tons of fuel gas and 320-360 kWh of power are required for one ton of para-xylene production. Refinery products like fuel gas, fuel oil, naphtha and diesel are used to satisfy fuel and power requirement of steam cracker and aromatics complex. Natural gas can be utilised as fuel for an integrated refinery cum petrochemicals complex while maintaining flexible product objectives.

Use of Natural Gas in Refinery
Natural Gas (NG) or Regasified Liquid Natural Gas (RLNG) can be used in refinery for various purposes such as fuel for process & utility heaters replacing fuel oil, feed and fuel for HGU replacing naphtha, fuel for GT and fuel for process heaters replacing fuel gas.

Each of the above-mentioned cases is discussed below in detail.

Natural Gas as Fuel for Process and Utility Heaters Replacing Fuel Oil: Use of natural gas as fuel replacing fuel oil provides the opportunity to either reduce or eliminate fuel oil generation from refinery by utilising bottom of the barrel processing technology. So far, DCU is one of the most economical options for bottom of the barrel processing. Other bottom of the barrel processing technologies that are available and used presently offer lower yield of distillates and do not eliminate fuel oil generation completely. New technology like slurry hydrocracking, which is on the verge of commercialisation, promises to offer better distillate yield and minimum residue generation. However, our discussion is restricted to DCU only since it has a proven operational track record. Typically, distillate yield (combining naphtha and diesel) of about 65 percent is obtained from DCU which may result in 10 to 12 per cent more distillate from refinery. Additional naphtha generated from DCU can be used as feedstock for naphtha cracker. Moreover, off gas from DCU contains good amount of ethylene, ethane and propylene. Ethylene and propylene can be recovered and used as petrochemicals feedstock after suitable treatment for impurities removal while ethane can be sent to steam cracker for production of petrochemicals feedstocks. Thus, replacing fuel oil with natural gas not only eliminates low value fuel oil generation but also enhances refinery and petrochemicals integration along with high value middle distillate production. This change over ie, replacing fuel oil by natural gas in existing fired heaters requires careful evaluation for thermal, mechanical and hydraulics adequacy of existing hardware particularly with respect to burners, tube metallurgy, refractory, air preheater system etc.

Natural Gas as Feed and Fuel for Steam Reforming: Hydrogen is one of the most important utilities in refinery. It is required to remove impurities like sulphur, nitrogen etc, from various refinery products and intermediate streams. Hydrogen is produced mainly by steam reforming of naphtha in refinery. Its requirement in refinery varies widely depending on crude processed and product specifications.

Typically, 4 tons of naphtha is required as feed and fuel to produce one ton of hydrogen while about 3.5 tons of NG is required to produce one ton of hydrogen. Use of NG as feed and fuel for hydrogen plant will release a good quantity of naphtha which can further be utilised for producing value added petrochemicals feed-stocks. Switch over from naphtha to natural gas requires certain modifications in various sections of HGU; these are listed on the next page.

  • Feed Pumping/Compression and Preheating: Naphtha pumps, Naphtha vapouriser and superheater are not required while natural gas compressor may be required
  • Hydrodesulphurisation: If RLNG is used as feedstock, pre-desulphurisation is not required due to very low sulphur content of RLNG . Additionally, NG or RLNG being olefin free, there will be no threat of olefins to reformer catalyst.
  • Reformer Firing: Stoichiometric air requirement will be changed due to change in hydrogen to carbon ratio of fuel, and it will call for burner tip modifications.
  • High Temperature Shift (HTS) reaction, Steam Generation and Pressure Swing Adsorpotion (PSA): Lower load on HTS reactor and lower steam generation due to less firing are expected. PSA is generally not affected by this change over.
Replacing naphtha with NG as feed and fuel for hydrogen plant not only helps the refiners produce more valuable products but also helps to reduce carbon footprint of the refinery. Typically, the changeover from naphtha to natural gas will help the refiners to reduce CO2 emission from HGU by 25 percent .

Natural Gas as Fuel for Gas Turbine (GT): GT is the main work horse for power generation in the refinery. A part of the power requirement of the refinery is satisfied by steam turbines utilising the co-generation potential that exists to generate various levels of steam required in the refinery. The balance part of power requirement is satisfied by Gas Turbine. Generally, naphtha is used as fuel for GT. Typically, 0.25 tons of naphtha is required to generate 1 MWh power from GT. When naphtha is replaced by Natural Gas as fuel for GT, it releases significant amount of naphtha which can further be utilised for valuable product generation. About 0.2 tons of NG are required for 1 MWh power generation. This switch over also helps refiners to reduce CO2 emission from GT by 25 to 30 percent.

Natural Gas as Fuel for Fired Heaters Replacing Fuel Gas: Fuel Gas is mainly generated from following sources of a refinery.
  • Saturated gas from CDU
  • Off gases from hydrodesulphurisation/hydrotreating units – Naphtha Hydrotreater (NHT), Kerosene Hydrotreater (KHT), Diesel Hydrotreater (DHDT) and Vacuum Gas Oil Hydrotreater (VGOHDT)
  • Off gas from Catalytic Reforming Unit (CRU)
  • Off gas from FCCU
  • Off gas from HCU
  • Off gas from DCU
  • Aromatics Complex
  • Naphtha Cracker Complex
Typical off gas yields from various refinery units, aromatics complex and naphtha cracker complex are shown in figure 2 on the previous page. Total fuel gas generation from refinery accounts for about 8 to 10 wt% of crude throughput whereas on integration with naphtha cracker and aromatics complex it can be as high as 15 wt% of crude throughput.

Table 1 shows the valuable components present in off gases from various refinery process units, aromatics complex and steam cracker complex.

Refinery which is processing crudes with light ends typically has a Saturated Gas Unit (SGU) to recover LPG. However, saturated off gas from this unit, primarily consisting of methane and ethane, still consists of some quantity of propane. Ethane and propane from SGU off gas can be recovered in a cryogenic separation unit after suitable purification and can be fed to the steam cracker for production of ethylene and propylene.

Hydrogen recovery from Refinery Off Gases (ROG) is an important aspect to reduce the size of ‘on-purpose’ hydrogen generation unit. This can be achieved by developing hydrogen balance model across the refinery, identifying constraints or flexibility of hydrogen usage and hydrogen pinch analysis for possible alternatives of hydrogen reuse from ROG. It should be noted that a careful techno-economic evaluation is required before implementing any project of hydrogen recovery from ROG. The reason behind is that, on one hand it reduces the size of the hydrogen generation unit and thus CO2 emission, on the other hand it degrades the quality of ROG in terms of calorific value and reduces the opportunity of burning hydrogen to reduce CO2 emission. However, for a larger hydrogen contributor, a dedicated recovery system is justified. CRU is one such source for Hydrogen recovery. Technip has developed a dedicated tool called HyN.DT for Hydrogen Management in order to help the refiners to optimise hydrogen recovery and size of 'on -purpose' hydrogen generation unit.

Off gas from FCC and DCU contains good quantity of ethane, ethylene, propylene and some propane. Separate recovery of ethylene and propylene through cryogenic separation after suitable treatment may be economical if quantity of gas is significant. Otherwise a combined recovery section with cracker complex may be considered. Ethane and propane separated from off gases are sent to cracker for further production of ethylene and propylene .

Recovery of valuable components like hydrogen, ethylene, ethane etc from off gases significantly reduces fuel gas quantity in the refinery leading to requirement of external fuel like natural gas. In other words, use of natural gas as fuel for the refinery will help in recovering valuable components from ROG leading to enhanced refinery profitability. Change over from fuel gas to natural needs careful evaluation of existing hardware, specially fired heaters with respect to thermal, mechanical and hydraulics adequacy.

Synergies between Refinery & Petrochemicals
Use of natural gas as refinery fuel unleashes a host of opportunities in terms of synergies between refinery and petrochemicals complex. The availability of full range naphtha (C5-165OC cut) as a result of utilising NG for steam reforming and gas turbines can be fruitfully utilised as feedstock for petrochemicals complex. From this full range naphtha, a portion of naphtha, ie, light naphtha (mainly C5) part can be utilised in steam cracker for production of ethylene and propylene while C7-C9 cut naphtha can be utilised for production of aromatics like benzene, toluene, para-xylene etc and middle cut can be blended in gasoline pool. Recent specifications of gasoline restricts aromatics content in gasoline thus restricting blending of reformate in gasoline pool and leading to use of alternate octane booster like isomerate and alkylate. Octane booster isomerate is produced by isomerisation of C5 stream of naphtha. However, if we use C5 stream to produce valuable products (like ethylene, propylene) in steam cracker, then alkylation unit can be considered for octane boosting .

Iso-butane reacts with olefins (propylene, iso-butylene etc,) to produce alkylates in presence of solid or liquid catalyst in alkylation unit. Generally FCC C4 cut is good feedstock to produce alkylates with Research Octane Number (RON) of 92 and above.

Significant quantity of ethylene and propylene can be recovered from FCC and coker off gases. In addition, ethane and propane recovered from saturated gases ex-CDU and from FCC and coker off gases can be utilised to produce ethylene and propylene by processing through steam cracker. Hence, the steam cracker can be designed as dual feed cracker (both liquid and gas) to take advantage of refinery off gases and any surplus naphtha leading to more flexibility in operation. Technip designed steam cracker is capable of taking any feed from ethane to gas oil providing a great deal of flexibility . SPYRO, the proprietary software from Technip is first principle-based software which is capable of predicting yield, run length etc accurately for any feed starting from ethane to gas oil. It is used by most of the ethylene producers worldwide to monitor and control cracking furnace performance. A great deal of synergy exists between refinery, aromatics complex and steam cracker complex. Off gases from FCC and coker containing good quantity of ethylene and propylene can be integrated with cold section of steam cracker. On the other hand, pyrolysis gasoline produced from steam cracker contains good quantity of xylenes and can be integrated with aromatics complex. Propylene produced from steam cracker complex and benzene produced from aromatics complex are the feedstocks for production of cumene and phenol which is the feedstock for producing bis-phenol and polycarbonates. Block flow diagrams given in table 2 and figure 3 show enhanced integration between refinery and petrochemicals complex when NG is used as fuel.

Reducing Carbon Footprint - A Bonus
In addition to achieving a good synergy between refinery and petrochemicals complex, use of NG as refinery fuel helps in reducing carbon footprint of the refinery especially when fuel oil is replaced by NG. Typically, replacement of fuel oil with natural gas gives about 30 percent reduction in CO2 emission and replacement of fuel gas with natural gas gives about 5 to 10 percent reduction in CO2 emission through fired heaters. This is in addition to CO2 emission reduction of 25 per cent in HGU and 25 to 30 percent in GT that can be achieved by replacing naphtha with natural gas.

A Case Study
A case study is performed with a base case of refinery complex of 15 MMTPA with a steam cracker and aromatics complex.

The refinery consists of CDU-VDU as primary unit, CRU and alkylation for MS production, FCCU and once through Hydrocracker Unit (OHCU) as secondary units and Delayed Coker Unit (DCU) is considered for bottom of the barrel processing.

Hydrotreating of all products like kero, diesel, naphtha and VGO is considered to meet product specifications required for downstream units and to meet environmental regulations. Since light naphtha (mainly C5 cut), which is fed into naphtha cracker, is not available for isomerisation for boosting the octane number of gasoline, an alkylation unit is considered for the same. C4 cut from FCCU is the feed to alkylation unit. Light naphtha (C5 cut) from NHT and hydrocracker along with hydrocracker bottom is the main feed to naphtha cracker.

Pyrolysis gasoline generated from naphtha cracker goes through aromatics separation unit where aromatics are separated and fed into para-xylene complex and raffinate is recycled back to naphtha cracker.

A butadiene extraction unit is considered within naphtha cracker complex. Hydrogen is recovered from CRU and naphtha cracker off gases through Pressure Swing Adsorption (PSA). Sulphur block includes Amine Treating Unit (ATU), Sour Water Stripper (SWS), Amine Regeneration Unit (ARU) and Sulphur Recovery Unit (SRU) as auxiliary units. Block flow diagram for base case refinery configuration is shown in figure 4 on the next page. An LP model is developed based on this configuration with maximisation of GRM as objective function with following basis.

  • Capacity: 15 Million Metric Tonne Per Annum (MMTPA) (~300000 BPSD)
  • Crude: 50% Arab Heavy and 50% Arab light
  • Desired Products: Ethylene, Propylene, LPG, Butadiene, Gasoline, ATF, Diesel, Benzene and Para-Xylene
Base case (without supplementary fuel like natural gas) material balance is performed using this LP model and product yields are shown in table 3 under base case. With the same configuration of base case, LP model was rerun with natural gas as fuel replacing ROG and naphtha as feed and fuel for HGU and GT.

The integration between refinery and petrochemicals complex is maximised by optimising refinery configuration in order to generate more value added products like ethylene, propylene, butadiene, benzene and para-xylene. Revised case (NG case) material balance is performed with natural gas as refinery fuel using LP model. A comparison of base case material balance and revised case material balance (NG case) is presented in table 3.

For base case, a part of the heavy products like vacuum residue and FCCU bottoms are utilised for generation of fuel oil to satisfy fuel requirement of the complex. However, for natural gas case, all the heavy products are sent to DCU resulting in more distillates and a marginal increase in coke production.

Fuel and loss are estimated based on total consumption of fuel gas, naphtha used for hydrogen generation and gas turbine and fuel oil consumption in boilers and heaters for base case. For natural gas case it is estimated based on natural gas and fuel gas consumption.

Comparison between base case and natural gas case material balance shows that about 7 wt% of crude is converted into valuable products like ethylene, propylene, LPG, butadiene, gasoline, benzene & para-xylene when natural gas is used as supplementary fuel for the refinery. Increase in production for these valuable petrochemicals feedstock is presented in figure 6.

Figure 6 shows that the increase in production for ethylene, propylene, butadiene, benzene and para-xylene is 64, 19, 33, 40 and 43 per cent respectively which has a significant impact on GRM. In addition to it, there is a significant reduction in CO2 emission. Estimated reduction in CO2 emission is about 2.5 per cent for entire complex. This reduction can be achieved despite the increase in production of petrochemicals feedstocks which consumes additional energy.

Conclusions
Use of natural gas as refinery fuel unleashes a host of opportunities to make refining and petrochemicals business more efficient. It benefits integrated refinery cum petrochemicals complex in multiple ways.
  • Use of natural gas releases a good quantity of naphtha which is normally used as feed and fuel for steam reforming and gas turbines. This naphtha can further be utilised for producing value added petrochemicals feed-stocks like ethylene, propylene, para-xylene etc.
  • Use of natural gas as fuel for refinery gives the opportunity of recovering valuable components like hydrogen, ethane, ethylene, propylene etc. from refinery off gas.
  • Replacement of fuel oil by natural gas enables refinery to process complete vacuum residue in DCU for enhancing the distillate yield.
In addition to above possibilities which help in significant improvement in GRM, use of natural gas as fuel also reduce carbon footprint of a refinery significantly. Price differential between natural gas and crude and more importantly price differential between natural gas and petrochemical feedstocks like ethylene, propylene, butadiene, benzene and para-xylene will remain as key driver to consider natural gas as fuel for refinery to improve GRM through better integration between refinery and petrochemicals complex.

Acknowledgement
Authors are thankful to the management of TPKTI for their kind permission to publish this article.

References:
  1. Tanmay Taraphdar, "Reducing carbon footprint - An integrated programme of process integration techniques lowers CO2 emissions levels in refineries through energy savings", PTQ, V 16, N°3, Q2 (2011), P 65 - 73.
  2. Sanjiv Ratan and Roland van Uffelen, "Curtailing refinery CO2 through H2 plant", ptq Gas 2008
The article was published in Petroleum Technology Quarterly (July,2012)