Search

Kurt Detrick (UOP)

API RP 751 (Safe Operation of Hydrofluoric Acid Alkylation Units) states “The use of gauge glasses should be minimized in HF service.”

Although gauge glasses can and have been used successfully in HF service, it is essential that proper design and very special operating procedures be followed in order to prevent serious incidents. In the past, gauge glasses were sometimes the only option to provide a reliable secondary indication of liquid levels in the HF Alky units in order to verify the sometimes-unreliable primary level instruments. However, with the advances in level instrument technology over the past decade, there are alternatives to gauge glasses to provide reliable confirmation of liquid levels in the unit.

In many cases, a magnetic level indicator can be used to replace the existing gauge glass relatively easily. Certainly, this has been the most common replacement technology for gauge glasses. When this is done, we typically recommend that instead of just a local reading for the magnetic instrument, a signal should also be sent to the control panel to allow tracking and trending of the magnetic level reading. This allows comparison of the level indication from the mag and from the primary level instrument and the operator can easily identify when there is a problem with one of the two instruments when the two signals diverge. So, you might give up something by replacing the gauge glass with a mag (the ability to visually verify the level), but you gain something (faster identification of a possible problem with the primary instrument).

We are also seeing increased use of remote-seal differential pressure level instruments in HF service. When properly designed and installed, this type of level instrument will have less potential to have a problem due to accumulation of iron fluoride scale in the instrument (compared to a typical displacement type level instrument). However, the remote seal DP cells are typically used as a primary level indicator and not as a replacement for the gauge glasses. We are also seeing some use of guided wave radar level instruments in HF service. The low conductivity of LPG and the presence of iron fluoride scale particles in the process fluid present some challenges for the guided wave instruments, but these can be overcome in some applications, and there are a few guided wave instruments in HF service.

At UOP, we typically specify a magnetic type of level instrument as the secondary level instrument in all acid services – with one exception. The only service where we might still specify a gauge glass in a new design is the Acid Ratio Glass in a pumped acid circulation unit, because indication of the time it takes for the separation of the two liquid phases and the ability to see the color of the acid are two things that a level instrument cannot give. However, it is possible to run the unit without the Acid Ratio Glass and we only include these in designs where the refiner requests it.

Note that the bottom of the fractionation columns in the HF Alky unit are not always considered “HF Service” at all locations. However, the column bottoms level glasses and instruments should be designed and operated as if it were HF Service because upsets can occur (such as power failures) that can result in significant HF in the bottom of these columns. If a gauge glass is lined up to the process when a power failure occurs, HF could get into the glass and cause a failure of the glass. So, it is best to avoid the use of gauge glasses on the bottom of these columns, and if a gauge glass is used, the special design and operating procedures for HF Service must be used.

Jim Norton and Chris Steves (Norton Engineering)

Glass on HF Alkylation units must have appropriate liners (e.g. Kel-F) so that the glass is not etched by the HF. Even with HF resistant liners installed gauge glasses should be equipped with isolation and purging facilities so that they can be flushed with clean material (i.e. isobutane) and isolated after use. Magnetic sight glasses have been successfully used in many refineries to replace gauge glasses and are especially good at detecting the acid/oil interface in acid settlers and separator boots.

Roberto Amadei (Chemical & Energy Development srl)

The naphtha catalytic reforming unit can be partially unloaded, by subtracting from its traditional feedstock the higher-boiling C6 hydrocarbons, including naphthenes, benzene and hexane.

Typically, the optimum allocation of this material unloaded from reforming is the isomerization unit. The deriving set-up of reforming and isomerization has the potential of generating value in several ways and in no way destroys any value. However, also in case of an allocation of the above material different from the isomerization, its unloading from reforming keeps a significant value generation potential.

The main components of the optimum reforming + isomerization set-up generated value are the following:

-hydrogen net production gain,

-gasoline yield gain,

-gasoline octane number gain, changeable at will into an additional gasoline yield gain,

-compliance, with margin, with the most severe limits of gasoline benzene content in the world, such as the 0.62 vol% content required by the United States Environmental Protection Agency, in the US resulting in saleable benzene content credits, significant energy savings, besides the hydrogen net availability gain one, emissions reduction of all of the pollutants and greenhouse gases types, in addition to the above, both in the gasoline production and consumption segments, also carrying out a gasoline lifecycle emission reduction of a few percent of CO2 equivalent,

-higher octane gasoline production capacity increase,

-improvement of the engine operation and maintenance.

The case study experimental results pointing out the above and the relevant theoretical explanation can for instance be seen in PTQ and Digital Refining 2013 Q1, article “Improved hydrogen yield in catalytic reforming”, or in “Gasoline Processes”, 2011 NPRA Q&A and Technology Forum.  With that said, a more detailed analysis of the generated value inherent to hydrogen net production gain looks to be useful. While it is clearly apparent the worldwide great value of hydrogen net production gain, a particular case instead has to be attentively examined: the case of North America. The reason for a particular attention is the North America availability of the very cheap shale gas.

Referring to the particular North America case, we premise that the optimum set-up of reforming and isomerization carries out the production of gasoline and hydrogen in lieu of fuel gas. With this due premise, we can conclusively deduce that the above hydrogen gain is much more convenient than the hydrogen production carried out by means of special units consuming the cheap shale gas (SMR). Precisely, neglecting here the gasoline-fuel gas replacement value, said hydrogen production gain is over three times cheaper, as far as the variable (operating) costs alone are concerned. In fact, in the case of the optimum reforming-isomerization set-up, the shale gas should be used, for combustion in the furnaces, in order to replace the fuel gas not produced anymore by reforming. In such a way the rate of substitution of fuel gas by shale gas is 1:1. On the contrary, any use of shale gas for producing hydrogen would require the consumption of more than 3 units of shale gas (taking into account all the energy flows, both consumed and produced by the SMR unit) per each unit of produced hydrogen (rate of substitution: >3:1). Moreover, depending on the specific refineries, the relevant hydrogen gain can even avoid the capital costs of either installations or revamps or even duplications of the special, highly energy consuming,hydrogen generation units.

On top of the value generation potential of the feedstock transfer interplay between isomerization andreforming, an interplay also exists between the whole of these two processes and FCC-gasoline post-treating.

The FCC-gasoline post-treating consumes hydrogen and energy and causes reduction of the FCC-gasoline octane number and yield, due to saturation of high-octane olefins. It is apparent that the above-described optimum set-up of reforming and isomerization, as it provides hydrogen gain, reduction of energy consumption and gasoline octane plus yield gain, counteracts the FCC-gasoline PT negative effects. Plus, it provides additional very low sulfur combined reformate-isomerate gasoline blending component, due to its yield gain, thus allowing a higher sulfur content of the post-treat FCC-gasoline for a given full gasoline sulfur content: this allows further reduction of the FCC-gasoline PT negative effects.

The two last paragraphs outline the qualitative aspect of the matter. As far as the quantities in play are concerned, HOP (Hydrogen-Optimization) analyzes and optimizes the operation and any asset of the specific refinery as a function of the specific refinery plant structure, supply slate and predicted FCC-gasoline PT upcoming additional needs of hydrogen, energy, gasoline octane and gasoline yield, also providing alternative cases results.

Here we owe an explanation: HOP is an Alliance established between Chemical & Energy Development and Prometheus, rendered very suitable by the worldwide hydrogen thirst that deserves the maximum operational efficiency. Chemical & Energy Development brings to the new Alliance its deep knowledge and practice of the specific, above indicated, technology and Prometheus brings to the new Alliance its deep knowledge and practice of planning and optimization procedures and of refinery engineering design. The provided gains, of hydrogen, energy, gasoline octane, gasoline yield and FCC-gasoline sulfur content, can be higher than the predicted FCC-gasoline PT upcoming additional needs and remain partially available for other foreseeable needs deriving from the

-existing or to be installed FCC pre-treats,

-heavy and sour crudes,

-medium-heavy products quality requirements; and

-tight oil.

Jocelyn Daguio (UOP)

CCR Platforming Unit Customers report 3.2 years on average between turnarounds. And 10 % of the units exceed 5 years. Although, catalyst change-out frequently determined this time previously, the ability to change out “on the-fly” while maintaining operations has removed this constraint.

Applying best practice in turnaround planning can extend future turnaround interval. Close monitoring both process and equipment performance is an enabler for exercising best practice during the turnaround.

For examples, evaluation of the combined feed exchanger, stabilizer column performance, fired heater efficiency, equipment pressure, compressor vibration and catalyst health conditions allow timely operation adjustment to prolong turnaround interval. Catalyst fines monitoring and fines control are essential to avoid unnecessary unscheduled turnaround due to fouling of equipment. For fixed bed reforming units, proper procedure of catalyst dump and screen and corrosion control during catalyst regeneration can reduce turnaround frequency or/and avoid unscheduled unit shutdown and turnaround.

Michael Crocker and Ka Lok (UOP)

For Isom units, the typical run length between maintenance turnarounds is approximately between two to five years, depending on naphtha complex flow schemes. Process evaluations include determination of catalyst activity and unit performance. Also included in the evaluation is the identification of any unit constraints during the run, which would include normal monitoring of process equipment. Traditionally, most ISOM units are corrosion-free due to the nature of the design of the unit (i.e., water is a poison to the catalysts), but where high HCl can possibly meet with free water (such as in the case of the Net Gas Scrubber in Penex and Butamer process units), online routine non-destructive testing techniques and monitoring of pipe wall thicknesses, where applicable, should be conducted.

Kurt Detrick (UOP)

Typical run lengths for HF Alkylation units have been increasing over the past couple of decades. The HF Alky run is typically tied to the FCC run length and the majority of units are planning for either 4 or 5 year run lengths. Some units plan for 3-year runs, and a very few are trying for 6-year runs.

A prolonged interval is not always the most profitable choice. Things that make longer runs less profitable are:

 - Higher probability of unplanned shutdowns. An unplanned shutdown almost always has a higher Lost Profit Opportunity (LPO) than a planned shutdown.

- Piping and Equipment inspection and replacement must be done more aggressively. The general guideline is that the inspection interval should not exceed ½ the estimated remaining life of the piping or equipment. Things that cannot be replaced without a shutdown (such as key valves, exchangers, piping and vessels) must be renewed more frequently (it is a lot easier to get a valve to seal properly for 4 years than 6 years).

- The longer the run length, the less meaningful a 1-year extension of run length becomes (diminishing returns). A 6-week planned shutdown is 5.8% of a 2-year run, 3.8% of a 3-year run, 2.9% of a 4-year run and 2.3% of a 5-year run. So, you don’t gain a lot by extending from a 4-year run to a 5-year run (but you do increase the risk of an unplanned shutdown).