Monday, January 16, 2017

Pilot-Operated Relief Valve


Like other pressure relief valves (PRV), pilot operated relief valves (PORV) are used for emergency relief during overpressure events (e.g., a tank gets too hot and the expanding fluid increases the pressure to dangerous levels). The difference between PORV and conventional PRV is that pilot valves use system pressure to seal the valve. A PRV typically uses a spring to hold the disc or piston on seat. The essential parts of a PORV are a pilot valve (or control pilot), a main valve, a pitot tube, the dome, a disc or piston, and a seat. The volume above the piston is called the dome.

PORV are also called pilot-operated safety valve (POSV), pilot-operated pressure relief valve (POPRV), or pilot-operated safety relief valve (POSRV), depending on the manufacturer and the application. Technically POPRV is the most generic term, but PORV is often used generically (as in this article) even though it should refer to valves in liquid service.

Mode of functioning
The pressure is supplied from the upstream side (the system being protected) to the dome often by a small pilot tube. The downstream side is the pipe or open air where the PORV directs its exhaust. The outlet pipe is typically larger than the inlet. 2 in × 3 in (51 mm × 76 mm), 3 in × 4 in (76 mm × 102 mm), 4 in × 6 in (100 mm × 150 mm), 6 in × 8 in (150 mm × 200 mm), 8 in × 10 in (200 mm × 250 mm) are some common sizes.
The upstream pressure tries to push the piston open but it is opposed by that same pressure because the pressure is routed around to the dome above the piston. The area of the piston on which fluid force is acting is larger in the dome than it is on the upstream side; the result is a larger force on the dome side than the upstream side. This produces a net sealing force.
The pressure from the pilot tube to the dome is routed through the actual control pilot valve. There are many designs but the control pilot is essentially a conventional PRV with the special job of controlling pressure to the main valve dome. The pressure at which the control pilot relieves at is the functional set pressure of the PORV. When the pilot valve reaches set pressure it opens and releases the pressure from the dome. The piston is then free to open and the main valve exhausts the system fluid. The control pilot opens either to the main valve exhaust pipe or to atmosphere.

Snap acting
At set pressure the valve snaps to full lift, it can be quite violent on large pipes with significant pressure. The pressure has to drop below the set pressure in order for the piston to reseat (see blowdown in relief valve article).

Modulating
The pilot is designed to open gradually, so that less of the system fluid is lost during each relief event. The piston lifts in proportion to the overpressure. Blowdown is typically short.



Comparison to non piloted pressure relief valves
Advantages
  • Smaller package on the larger pipe sizes.
  • More options for control.   
  • Seals more tightly as the system pressure approaches but does not reach set pressure.
  • Control pilot can be mounted remotely.
  • Some designs allow for changes in orifice size within the main valve.
  • can be used in engines
Disadvantages
  • More complex, resulting in various fail-open failure modes.
  • More expensive at smaller sizes (starts to even out as pipe size increases).
  • Small parts in pilot valve are sensitive to contaminant particles.
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Tuesday, October 4, 2016

Hydrogen - The Key Refinery Enabler

By. Stephen Harrison, Linde HiQ

In the 21st century, the term “scraping the bottom of the barrel” has become quite literal to the refining industry and hydrogen comes to the fore as a means to do just this

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Only a few decades ago, the thick, heavy crudes being utilised today would not have even been a consideration for the production of mainstream products and were used mainly as bunker fuels. Thirty years ago crude quality was a good match with what was being demanded by the market, but today’s refiners are being compelled to dig deeply into the dregs of the remaining resources and must upgrade these crudes to reduce sulphur content and to keep up with market demand and environmental regulations. Hydrogen is therefore absolutely critical to convert this poor quality crude oil into modern-day products, and to comply with strict environmental mandates.

Although these heavy crudes are actually cheaper, refineries are faced with the additional expense of upgrading to sophisticated processes to refine them to the required standards and product slate meeting demand. The alternative is to pay a premium for the lighter crudes. This awkward choice has already impacted many refineries, notably on the east coast of the US , where refineries originally built to process light and sweet crudes have had to shut down because they could not fund the technology upgrade necessary to process heavier crudes. The cost of hydrogen is part of the premium that the refiners must pay to process cheaper crudes economically.

The challenge is made more complex by the fact that no two refineries are alike and that the naturally occurring hydrocarbon distribution in crude does not always match customer demand. Various additional processing steps are required to re-adjust the molecules, reshape them and remove contaminants to ensure the refinery products meets the requirements for end-use and the product demand profile, as well as environmental performance.

Hydrogen is a key enabler allowing refineries to comply with the latest product specifications and environmental requirements for fuel production being mandated by market and governments and helping to reduce the carbon footprint of their plants.

Margins are tight in the highly competitive refinery business, a situation exacerbated by the costs of creating low sulphur fuels from heavier, more sour crude, as the world’s crude oil resources dwindle. The sulphur content of the world’s diminishing crude oil resources is higher than ever before as oil companies are forced to tap into a cheaper but lower quality of crude that requires more refining to meet tightening environmental standards and while maximising margins. Product sulphur levels are lower than ever before — for instance, 30 parts per million (ppm) in gasoline and 15 ppm in diesel fuels.

Growth in demand
From a global perspective hydrogen is demonstrating significant growth. Large heavy crude oil reserves, still under development, may increase the hydrogen demand ever further. Two examples are the extra heavy crude oil in the Orinoco Belt in southern of Venezuela and the Canadian Oil Sands. While there are many refinery configurations, all refineries harness large quantities of hydrogen across a spectrum of operations. Hydrogen is utilised in several refining processes, all aiming at obtaining better product qualities. The main processes include hydrotreating of various refinery streams and hydrocracking of heavy products.

While the lighter, sweet crudes require less processing, the heavier, sour crudes contain higher levels of sulphur, other contaminants and fractions. Processing them typically begins with the same distillation process as for the sweet crudes to produce intermediate products, but additional steps are necessary.

Hydrotreating is one such process, introduced to remove sulphur, a downstream pollutant, and other undesirable compounds, such as unsaturated hydrocarbons and nitrogen from the process stream. Hydrogen is added to the hydrocarbon stream over a bed of catalyst that contains molybdenum with nickel or cobalt at intermediate temperature, pressure and other operating conditions. This process causes sulphur compounds to react with hydrogen to form hydrogen sulphide, while nitrogen compounds form ammonia. Aromatics and olefins are saturated by the hydrogen and lighter products are created. The final product of the hydrotreating process is typically the original feedstock free of sulphur and other contaminants. Single or multiple product streams (fractionated) are possible, depending on the process configuration.

The hydrocracking process is a much more severe operation to produce lighter molecules with higher value for diesel, aviation and petrol fuel. Heavy gas oils, heavy residues or similar boiling-range heavy distillates react with hydrogen in the presence of a catalyst at high temperature and pressure. The heavy feedstocks are converted (cracked) into light distillates — for example, naphtha, kerosene and diesel — or base stocks for lubricants. The hydrocracker unit is the top hydrogen consumer in the refinery. Hydrogen is the key enabler of the hydrocracking to reduce the product boiling range appreciably by converting the majority of the feed to lower-boiling products. Hydrogen also enables hydrotreating reactions in the hydrocracking process; the final fractionated products are free of sulphur and other contaminants. Other refinery processes including isomerisation, alkylation and tail gas treatment also consume small amounts of hydrogen.

Critical decision
Considering that the cost of a refinery expansion can be in the order of US$1billion, with hydrogen supply representing in some cases about 10% of this investment, the decision concerning the optimum way to source this hydrogen has become a critical one. In many cases, refinery operators see the investment into hydrogen supply as a defensive outlay necessary to remain competitive in the market.

Hydrogen is required in large volumes – typically 10-200 000 Nm3/hr on a refinery, but is needed for a variety of applications in several different scales of supply. Due to hydrogen representing a significant percentage of a refinery’s total investment, a pivotal decision confronting operators is the supply method. There are essentially three options for large scale hydrogen supply.

Firstly, the refiner can build an on-site hydrogen production plant, which it owns and operates using its own personnel. An advantage of this option is that hydrogen production becomes fully integrated with the other refinery processes. While this enables the refinery to keep control of its own hydrogen supply, this option requires more capital and demands skilled attention from the refinery labour force for efficient operation, maintenance and repair. If the in-house team is unable to operate the plant efficiently, the refinery will incur financial losses, including increased consumption of natural gas and even other more costly raw materials such as naphtha, water and power. Loss of hydrotreated products attributed to poor reliability may also be a concern.
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Friday, July 10, 2015

Optimizing a Boilers Efficiency

Combustion Efficiency and Excess Air
To ensure complete combustion of the fuel used, combustion chambers are supplied with excess air. Excess air increase the amount of oxygen and the probability of combustion of all fuel.

when fuel and oxygen in the air are in perfectly balance - the combustion is said to be stoichiometric

The combustion efficiency will increase with increased excess air, until the heat loss in the excess air is larger than than the heat provided by more efficient combustion


Typical excess air to achieve highest efficiency for different fuels are
  • 5 - 10% for natural gas
  • 5 - 20% for fuel oil
  • 15 - 60% for coal

Carbon dioxide - CO2 - is a product of the combustion and the content in the flue gas is an important indication of the combustion efficiency.

An optimal content of carbon dioxide - CO2 - after combustion is approximately 10% for natural gas and approximately 13% for lighter oils.

Normal combustion efficiencies for natural gas at different amounts of excess air and flue gas temperatures are indicated  below:

Flue Gas Loss Combustion Oil
The relationship between temperature difference flue gas and supply air, CO2 concentration in the flue gas, and the efficiency loss in the flue gas combustion oil, is expressed in the diagram below. 

Example - Heat Loss Flue Gas
If the temperature difference between the flue gas leaving a boiler and the ambient supply temperature is 300 oC and the carbon dioxide measured in the flue gas is 10% - then, from the diagram above, the flue gas loss can be estimated to approximately 16%.
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Wednesday, December 3, 2014

The Operation of Refinery Hydrogen Systems

The refinery hydrogen distribution system usually comprises a set of hydrogen main headers (pipelines) working at different pressures and hydrogen purities. Many makeup and recycle compressors drive the hydrogen through this complex network of consumer units, on-purpose production units, and platformers (see Figure 1a). On-purpose hydrogen plants generate high purity hydrogen at different costs while net production units are platformers generating low purity hydrogen as a byproduct. Hydrogen streams with different purities, pressures and flow rates coming from make-up hydrogen plants and platformers are supplied to multiple consumer units through the hydrogen main headers. Purge streams from hydrotreaters containing non-reacted hydrogen are partially recycled and mixed with fresh hydrogen streams from hydrogen headers before re-routing them to consuming units . 

The remaining off-gas stream is burnt as fuel gas. By controlling the fuel gas flow, the purity of the recycled hydrogen stream can be adjusted (Figure 1b). The major hydrotreater operating constraint is a minimum hydrogen/hydrocarbon ratio along the reactor in order to avoid carbon deposition over the catalyst and its premature deactivation. As the catalyst cost is very significant, an effective operation of the hydrogen network will help to increase the catalyst run length, thus boosting the refinery profitability. Moreover, some consuming units may have group of membranes that can be activated to separate and recycle higher-purity hydrogen streams to the hydrogen piping network (Figure 1b).

The MINLP mathematical model

The integrated management of the whole refinery hydrogen network is a very challenging task that requires effective computer-aided optimization tools. The key principle behind the hydrogen management is the fact that not all processes need hydrogen of the same purity. This section describes the proposed MINLP framework for the cost-effective management of refinery hydrogen systems. Main model decision variables and constraints permit to write accurate hydrogen mass balances in terms of purity and flowrate for every stream. The model aims at systematically improving the use of existing refinery hydrogen supplies as a network problem. Its main goal is to minimize the hydrogen production cost while satisfying predefined hydrocarbon production targets, actual  topological and operational restrictions as well as minimum utility hydrogen needs at desulphurization reactors. Problem constraints related to hydrogen production units, headers and consumer units are introduced below.

1. Hydrogen production unit constraints. As previously stated, a refinery system usually comprises several production units, i.e. H2-plants and catalytic reformers, that can simultaneously be supplying hydrogen streams with different levels of purity and pressure to the pipeline network. Therefore, if an existing production unit uÎPU is being operated in the refinery, i.e. Yu = 1, equations (1) and (2) will enforce the corresponding lower and upper limits on hydrogen flowrate (Qu) and purity (Pu), respectively. However, it is worth mentioning that hydrogen streams generated by platformers as a byproduct usually have a certain flowrate and purity, and consequently they become model parameters. Here, it should be noted that the optimization model will be able to choose the most convenient operating conditions for the alternative hydrogen sources in order to meet hydrogen demands at minimum cost. Equation (3) defines the amount of hydrogen feed that is being directly supplied from production units to alternative hydrogen headers hÎH and consumer units uÎCU.

2. Hydrogen pipeline constraints. The refinery pipeline network receives high-purity hydrogen streams coming from producer units and medium/low-purity streams from platformers and consumer unit recoveries. Different headers are usually operated at a given hydrogen purity and partial pressure. Equations (4) and (5) enforce a hydrogen mass balance between inlet and outlet streams in every header. Therefore, if at a given moment the hydrogen production exceeds the actual consumption, the balance is satisfied by supplying the surplus hydrogen to the refinery fuel gas system. In turn, equation (6) computes the header hydrogen purity (Ph) taking into account the total hydrogen flowrate in the header (Qh), the flowrate of hydrogen inlet streams coming from alternative sources (quh) and their corresponding purities (Pu and Poutu).

3. Hydrogen consumer unit constraints. Consumer units carry out different hydrotreating operations by utilizing the hydrogen streams available in the network. Equation (7) computes the total hydrogen feed (Qinu) being supplied to consumer unit u from different sources while the bilinear equation (8) determines the actual purity (Pinu) of the combined hydrogen inlet stream. In turn, equation (9) forces a minimum purity requirement for the combined inlet stream of every consumer unit. The minimum hydrogen need for processing the oil fraction (cu) being treated in unit u is specified by equation (10) by enforcing a minimum hydrocarbon/hydrogen ratio. Equations (11) and (12) predict the flowrate (Qoutu) and purity (Poutu) of the non-reacted hydrogen stream from unit u. These estimations are obtained by using non-linear correlations fq and fp that are functions of the flowrate and purity of the inlet streams as well as the inherent features of the oil fraction being hydrotreated in the unit, i.e. density, sulphur and aromatics content, etc.  Finally, equation (13) determines the amount of off-gas that is being recycled and supplied to headers and other consumer units.

4. Objective function. The proposed objective function computes the total hydrogen cost required for hydrotreating pre-specified oil-fractions. The non-linear correlation fc calculates the total production cost as a function of the current hydrogen purity and flowrate in each producer unit u. This function may easily accommodate internal and/or external hydrogen suppliers with different cost and restrictions. Alternatively, the proposed model with minor changes could be used for maximizing the refinery profitability. In this case, the model may optimally select the oil-fractions to be hydroteated subject to minimum and maximum oil-fraction demands and a maximum hydrogen availability. This scenario seems to be particularly interesting for dealing with ultra low-sulphur targets and, consequently, future hydrogen shortfalls.

Case study

A case study of a H2 network comprising two on-purpose plants, two platformers and eight hydrotreating units with different needs of hydrogen purity and flowrates is depicted in Figure 2a. In turn, Figure 2b shows the optimal hydrogen balance when the HD3 hydrogen purity need decreased to 95.9%. The optimal balance generated by the MINLP model with modest CPU time obtained a 25% reduction in  H2 production cost.

Conclusions and future work

An MINLP-based approach has been presented to optimally manage complex hydrogen networks of refinery operations. The proposed model is able to systematically reduce utility cost by increasing hydrogen recovery in consumer units and reducing production cost in the alternative hydrogen suppliers. This project stage is mainly focused on a rigorous treatment of hydrogen mass balances. Future work will aim at extending the model to also consider actual compression costs and operational restrictions as well as the use of alternative separation units (membranes) to recycle higher-purity off-gas to consumer units. 
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