Hydrocracker revamp for Grangemouth refinery
BP Oil’s Grangemouth refinery has completed an extensive revamp of its hydrocracker and FCC, reducing production of fuel oil and upgrading to middle distillates to meet a growing market need
Marco Giannelli, BP Oil Grangemouth Refinery
Nigel Unsworth and Dave North, Foster Wheeler Energy Ltd
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Between 1993 and ‘94 BP Oil spent several months developing a strategy for its Grangemouth, UK, refinery for the next 10 years-plus. It was decided to invest in placing the refinery in a good position to meet future market demands. The main drive was to minimise fuel oil production by upgrading it to higher value distillate products.
The investment strategy utilised the refinery’s existing strengths and configuration. It entailed: revamping the hydrocracker to increase throughput and convert to middle distillate mode; revamping the FCC to process heavier feeds; and the construction of a solvent deasphalting (SDA) unit to produce additional FCC feed.
The lighter portion of existing FCC feed was planned to be taken to make up the additional feed for the revamped hydrocracker, leaving capacity in the revamped FCC to process the heavier feed from the new SDA unit. Notwithstanding the synergy between the three elements of this strategy, the revamp of the hydrocracker unit in particular was seen to have merit as a standalone project because of the flexibility it brought to the refinery operation.
The hydrocracker capacity was 232m3/h (35000bpsd) and the refinery was operating to a very tight hydrogen balance. Also, the hydrocracker was producing a light product slate, kerosene being the heaviest cut. At the time of the strategy review, motor gasoline was surplus in Europe and forecast to remain so, while middle distillates were forecast to be in deficit.
Increasing the throughput of the hydrocracker in its previous operating mode would have required large investment in additional hydrogen production, making it uneconomic. The route chosen to convert the hydrocracker to produce a heavier feed slate (termed middle distillate mode) had several advantages:
- It allowed throughput increase without the need for expensive investment in additional hydrogen manufacture
- It modified the refinery product slate to better meet forecast demands, increasing diesel and jet A1 manufacture, and decreasing light naphtha and motor gasoline manufacture
- It positioned the refinery very well to meet ever-tightening environmental diesel specifications, for example on sulphur, and in addition allowed the potential for early entry into the ultra-low sulphur diesel market.
The new middle distillate operating mode produced additional hydrocracker kerosene, thus increasing the refinery’s jet A1 make, plus a new diesel cut of extremely high quality for use as a diesel blend component. The hydrocracker had been achieving four-year catalyst runs, to match turnaround intervals. Any shortening of catalyst runs would either have led to catalyst change outs between turnarounds, or more frequent turnarounds.
Converting the unit to a middle distillate hydrocracker at a higher throughput meant that by balancing pretreatment versus hydrocracking catalyst operating conditions, the unit could still operate on a four-year catalyst cycle.
It became evident that significant modification of the HP circuit would be too costly to remunerate, so the philosophy adopted was to increase throughput up to the limit of the HP circuit, estimated to be in the range 10–20 per cent above prevailing light distillate production capacity. This was considered closely during the feasibility study. Also, the construction of additional tankage to accommodate the new hydrocracker diesel cut, plus the overall increase in refinery diesel production, was identified as being too costly.
A lot of logistic modelling work of the offsites was carried out, and a solution found involving the reallocation of duties for several existing tanks, thus eliminating the requirement for additional tankage.
It was decided during the pre-feasibility study not to work with just one catalyst vendor, so as to avoid designing the unit to meet the requirements of only one catalyst system. This would potentially have led to a design that was catalyst specific, which might not have been optimal in terms of revamp cost. For this reason more than one catalyst vendor was consulted.
It was also decided at an early stage that the revamp should still allow the hydrocracker to operate in light distillate mode, making it an extremely flexible unit. None of the catalyst vendors consulted were aware of any other hydro-cracker that could operate over such a large range of recycle cut points. This flexibility also meant that the refinery would be better placed to change its product slate to match demand on the day, thus maximising profit.
Pre-feasibility studies were based on preliminary catalyst performance data developed by BP. These data were later superseded by performance predictions obtained from several potential catalyst suppliers during the feasibility study itself as described below.
The hydrocracker unit at Grangemouth came onstream in the early 1970s. It was designed to process 199m3/h (30000 bpsd) of Light Arabian vacuum gasoil feedstock to produce a range of light distillate products, the heaviest being kerosene. Two-stage hydrocracking technology licensed by Esso Research and Engineering was employed.
The unit featured four reactors (three first stage and one second stage), a condensing steam turbine-driven centrifugal recycle gas compressor and conventional cold HP and LP separators. The fractionation section comprised a main fractionator to extract kerosene and recycle (unconverted) oil, with a light ends recovery section producing a wide range of naphtha and lighter products.
By the early 1980s, the availability of relatively sweet North Sea feedstock had enabled unit capacity to be raised to 212m3/h (32000bpsd). However, a major explosion and fire in 1987 disabled the unit for more than two years while the Rehabilitation Project (also engineered by BP and Foster Wheeler) was completed.
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