Jul-2019

Refinery catalyst testing

Selecting the best catalyst for a unit demands thorough evaluation of the available options.

TIAGO VILELA
Avantium

Article Summary

Refineries change out catalysts periodically, reloading either with fresh or regenerated used catalysts. Loading schemes include two or more catalysts. For every changeout or loading, the question must be answered: which catalyst or catalyst combination is most appropriate for the next cycle of the unit?

Choosing the best catalyst is of crucial importance. It relates directly to the profitability of the refinery, and therefore represents a tremendous opportunity for increasing refining margins. It has a huge impact on both daily operations and long term planning. For hydrocrackers, such a decision will have a major effect on the economics of the refinery. Also, a catalyst loading represents a significant investment ($10-$20 million), which surely justifies a thorough evaluation of more of the available options.

In recent years, comparative catalyst testing in pilot plants has become the best practice for evaluating catalyst performance and the profit impact of process options. When selecting catalysts, refiners consider several factors: expected performance, price, guarantees, technical service, and previous experience with prospective suppliers.

Important performance parameters include:
• Catalyst activity
• Yields (selectivity)
• Catalyst cycle life
• Deactivation rate
• Hydrogen consumption/ production
• Product properties
• Yield flexibility
• Feedstock flexibility (including feed rate changes)
• Pressure drop build-up (dP+).

These terms are explained below in some detail along with some of the questions that commonly arise when considering process changes.

Process parameters for pilot plant studies
Feedstock quality
Refiners frequently change feedstocks before determining the impact of such changes in a pilot plant study. Failure to do so can be exceedingly expensive.

Most refinery planning models assume that all hydrocracker feeds give the same product distribution, regardless of endpoint. They predict that raising feedstock endpoints can be equivalent to converting heavy fuel oil into naphtha and middle distillates. Over small ranges, most vendor kinetic models give similar results. But in fact, especially for FCC heavy cycle oil and heavy coker gasoil, raising endpoints by just a few degrees can be equivalent to pumping liquid coke into the unit. Deactivation accelerates. Conversion drops immediately. To reattain conversion, temperatures must be increased accordingly. The incremental conversion is largely thermal, giving relatively large amounts of gas. In cases where this has happened, a pilot plant test readily would have revealed the impacts in advance.

Catalyst activity
In practice, catalyst activity in fixed bed systems refers to the average temperature required to achieve one or more major primary process objectives, such as sulphur removal or conversion of high boiling fractions into lighter fractions. In lube base stock hydroprocessing, primary objectives may include aromatics saturation, wax removal, or colour stabilisation. Typically, refiners base operations on weighted average bed temperature (WABT) or catalyst average temperature (CAT). Average temperatures are used because hydroprocessing units are adiabatic.

Catalytic reforming is endothermic; temperatures go down as feeds pass through the reactors. Hydrotreating and hydrocracking are exothermic; temperatures go up as feeds pass through the reactor(s).

Catalyst deactivation
As catalysts age, they lose activity as coke deposition fouls active sites. Hydrogen inhibits coke formation, so increasing hydrogen partial pressure (H2PP) decreases coke-induced deactivation. Feed contaminants and process upsets also cause deactivation. To compensate for activity loss, operators increase temperature to maintain performance (for instance, sulphur removal or conversion).

Deactivation rate can be expressed as temperature increase requirement (TIR) expressed as degrees per unit of time. Consider the following sample calculation. A diesel hydrotreater can make ultra low sulphur diesel (ULSD) at a WABT or CAT of 360°C at the start of a cycle. Due to metallurgical constraints, the maximum average temperature is 425°C. If the TIR is 2°C per month, the projected catalyst life (barring upsets or unacceptable pressure drop) is 2.7 years. A tacit assumption here is that deactivation is linear. In fact, TIR tends to increase, especially at higher temperatures near end of run.

Yields (selectivity)
Yields and selectivity are closely related. A typical refinery yield report includes the following:
• Methane (C1)
• Ethane (C2)
• Propane (C3)
• Butanes (i-C4 and n-C4)
• Light olefins (propylene and butylenes)
• Light naphtha (primarily pentanes) defined with a boiling range
• Heavy naphtha
• Light gasoil (may also be called kerosene)
• Heavy gasoil
• Unconverted oil
• Hydrogen

Yield tables show results in both wt% of feed and vol% of liquid feed. The sum is 100 wt% plus H2 consumption or production (wt%).

Selectivity is the relative yield of a product or group of products. Selectivity calculations might exclude unconverted oil. So-called ‘gas make’ is C1+C2+C3. Naphtha selectivity is the sum of light and heavy naphthas. Middle distillate selectivity is the sum of light and heavy gas oils.

With respect to selectivity, hydrocracking can be quite flexible. For a given catalyst, operating conditions can be adjusted to emphasise either naphtha or middle distillates. Table 1 gives an example for a recycle hydrocracker with a high activity zeolite based catalyst: