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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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. Y_u = 1, equations (1) and (2) will enforce the corresponding lower and upper limits on hydrogen flowrate (Q_u) and purity (P_u), 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 (P_h) taking into account the total hydrogen flowrate in the header (Q_h), the flowrate of hydrogen inlet streams coming from alternative sources (q_uh) and their corresponding purities (P_u and P^out_u).

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 (Qⁱⁿ_u) being supplied to consumer unit u from different sources while the bilinear equation (8) determines the actual purity (Pⁱⁿ_u) 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 (c_u) being treated in unit u is specified by equation (10) by enforcing a minimum hydrocarbon/hydrogen ratio. Equations (11) and (12) predict the flowrate (Q^out_u) and purity (P^out_u) 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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Flare Gas Recovery (FGR) to Minimize Wastes and Economical Benefits

Abstract

One of the safe and pressure relieving systems in oil and gas refineries as well as petrochemical complexes, is the relief header with the flare stack being the last component. In this network all the excess gases are collected and sent to flare stack to be burnt. A great amount of these gas mixtures has a high heating value and in some cases it can even be used as the raw material forvarious units.

It is clear that burning this gas mixture in flare stack causes environmental problems like air and noise pollution and also is a financial waste. In this paper a step by step approach and calculations are given to calculate and discuss flare gas recovery benefits for refineries. The method contains data gathering of flare line’s composition and other conditions, simulating of data and calculate financial benefits for the case study by available equations. Therefore, Tabriz oil refinery flaring system and available equation for flare system are used as a case study.

Flare gas mixture in Tabriz refinery consists of a wide spectrum of gases. After studying the methods for flare gas recovery and economic analysis, a suitable method with a single stage compressor is selected. The financial gain of this method is around 105,000 $ per year. Considering the implementation of Kyoto protocol in Iran, flare gas recovery will be more economical.

Keyword: Flare gas recovery, FGR, FGR calculations, FGR simulation

Introduction:

Even in most advanced countries only a decade has passed from flare gas recovery technology, thus the method is a new methods for application in refineries wastes. Of such countries active in flare gas recovery are USA, Italy, the Netherlands, and Switzerland.

To recover flare gas, after collecting from header and flare knock-out drum, flare gas passes through a compressor. The compressor design and selection is the main part of the plan.

After gas compression based on refinery structure or related unit, the gases used as a feed or fuel. If required, to reach entrance gas temperature to flare gas recovery unit and external gas temperature from this unit to an optional temperature, heat exchangers are used.

To compress gases and to design flare gas recovery unit, in general, liquid ring compressors or reciprocating compressors are used. Advantage of first type is that gas is cooled during compression by heat transfer of gas through water inside compressor (usually water). It is possible to use amine instead of water in such compressor to separate hydrogen sulfide from flare gases.

Reciprocating compressors are purchased easily than the first type, also spare parts provision, repair and maintenance is much easier. If using reciprocating compressors, please note that it will explode if temperature exceeds over allowable limit.

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Coriolis gas flowmeters

Recent advances in the development and performances of Coriolis meters have meant that the measurement of the mass flow rate of gases, such as natural gas for custody transfer applications, is now a reality.

International standards

This has been reflected by the large acceptance of this technology within the natural gas industry. As an example, Micormotion has supplied 5,000 Coriolis meters for natural gas applications in the last 3 years. This industrial acceptance motivated ISO to develop a standard through the ISO Technical Committee—ISO Standard TC30/SC12. In addition to this ISO standard, there is also an engineering technical report prepared by AGA entitled Coriolis Flow Measurement for Natural Gas Applications.

For additional information on Coriolis meters and their use in liquid service, see Inference liquid meters.

Although there is no ISO standard for natural gas measurement using Coriolis measurement, some countries have issued type-approval certificates for natural gas measurement using Coriolis meters. These countries include: The Netherlands (Netherlands Inst. for Metrology and Technology), Germany (Physickalisch-Technische Burdessarstalt), Canada (Measurement Canada), and Russia (Gosstandard).

Coriolis meter overview

A Coriolis meter comprises two main parts:

§  A sensor (primary element)

§  A transmitter (secondary element)

See Fig. 1.

Fig. 1—Coriolis flowmeter (Courtesy of Daniel Industries).

With this design, the gas flows through a U-shaped tube. The tube is made to vibrate in a perpendicular direction to the flow. Gas flow through the tube generates a Coriolis force, which interacts with the vibration, causing the tube to twist. The greater the angle is twisted, the more the flow increases. The sensing coils, located on the inlet and outlet, oscillate in proportion to the sinusoidal vibration. During the flow, the vibrating tubes and gas mass flow couple together because of the Coriolis force, causing a phase shift between the vibrating sensing coils. The phase shift, which is measured by the Coriolis meter transmitter, is directly proportional to the mass flow rate. The vibration frequency is proportional to the flowing density of the flow. However, the density measurement from the Coriolis meter is not normally used as part of the gas measurement station. Like other meters, the Coriolis is usually mounted in a meter tube. Because the device is insensitive to flow disturbances, there is no requirement for any form of flow conditioning, straight lengths, or meter tube.

Theory of operation

Coriolis meters operate on the principle that, if a particle inside a rotating body moves in a direction toward or away from the center of rotation, the particle generates inertial forces that act on the body. Coriolis meters create a rotating motion by vibrating a tube or tubes carrying the flow, and the inertial force (Coriolis force) that results is proportional to the mass flow rate. By measuring the amount of inertial force or deflection, it is possible to infer the mass flow rate. It is this phenomenon that is harnessed within the Coriolis flowmeter.

It is also important to consider any additional uncertainty associated with the through-life stability of the Coriolis meter. There are two main influencing factors: the change in flow-tube structural characteristics caused by erosion of the tube wall by abrasive particles and the coating of the flow tube by debris. Abrasion of the flow tubes by abrasive particles can directly affect the flow calibration of the meter. Coating of the flow tubes by debris is only a concern at low fluid flow velocities when the meter is not self-cleaning. This influence does not affect the meter’s calibration and only affects the meter’s zero. It can be corrected by regular zero checks for drift and zeroing, if required. Both of these influences can be identified as occurring under flowing conditions by monitoring the drift in flowing density over time.

Advantages and disadvantages

The advantages and disadvantages for Coriolis meters are shown in Table 1.

Table 1

Sizing

Gas Coriolis meters, like all Coriolis meters, are mass devices. The sensitivity of the meter to measure small amounts of mass flow determines the low end of the metering range. The upper end of the measurement range is most often determined by the largest acceptable pressure loss. The pressure loss across the meter increases with flow rate and the corresponding velocity through the meter. Velocities through the meter can be a substantial fraction of the speed of sound but clearly should not exceed about 0.5 Mach.

References

1.    ISO Standard TC30/SC12, Measurement of Fluid Flow in Closed Conduits—Mass Methods. 2005. Geneva, Switzerland: ISO Technical Committee.

2.    Coriolis Flow Measurement for Natural Gas Applications, technical report. 2001. Washington, DC: AGA.

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OBQ and ROB

ON BOARD QUANTITY (OBQ): All the oil, water, sludge and sediment in the cargo and associated lines and pumps on a ship before loading a cargo commence. (this term may not apply to product movement).

QUANTITY REMAINING ON BOARD (ROB): All the oil, water, sludge and sediment in the cargo tanks and associated lines and pumps on a ship after discharging a cargo has been completed, excluding vapour but including clingage. (this term may not apply to product movements)

Determine the OBQ/ROB for Liquids as follows:

(1)    By measurement determine the depth of liquid in each tank. Measure-ments should be taken at as many points as possible to ascertain if the liquid covers the tank bottom.

(2)    Where there is a sufficient depth of liquid determine its temperature. If not assume the material to be at standard temperature.

(3)    Calculate and record corrected volumes using where appropriate :

(a)    Special dip tables or the wedge formula if the liquid does not cover the bottom of the tank.

(b)   Trim/list corrections if the liquid covers the bottom of the tank.

Note: When applicable, estimate the volumes of oil residues adhering to the surfaces of the tank walls and structure. Add this volume to the quantities determined above.

(4)    Where possible obtain a sample of the OBQ/ROB.

Note:

Slops which are to be loaded on top should be included in the OBQ/ROB report. Record on the report from the nature of the materiel and the method used to determine the volume in each compartment. Material in compartments not receiving cargo should also be measured and reported on an OBQ/ROB report from.

This report should be signed by the interested parties. If the vessels officer signed under protest a note shall be made as to whether the vessel chose to have a survey made by another company on its behalf .It is strongly recommended that Dry Tank Certificates are not signed by inspectors. Refer to specific instructions issued by interested parties concerning Dry Tank Certificates.

If there is an unresolved dispute between the vessels personnel and the inspector or other interested parties as to the quantity and character (liquid or non-liquid) of the ROB this shall be reported immediately by telephone or telex to all the parties concerned and noted on the OBQ/ROB report.

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