Typical Industrial Control Valve

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02 Nov 2017

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Figure 2.1(a) Conventional MPF metering using separators.......................................................................6

Figure 2.1(b) On-line Multi phase flow metering..........................................................................................6

Figure 2.2; Principle of thermal flow meter..................................................................................................7

Figure 2.3; Illustration of steady-state flow regime map for a vertical pipe..................................................9

Figure 2.4; Illustration of steady-state flow regime map for a horizontal pipe.............................................10

Figure 3.1; Typical Industrial control valve..................................................................................................14

Figure 3.2; typical control valve arrangement in a process line..................................................................16

Figure 3.3; PID Controller Schematic.........................................................................................................20

GANTT CHART …..…………………………………………………………………………………...............25

REFEENCES ………………………………………...............................................................................26

1.0 INTRODUCTION

1.1 BACKGROUND OF STUDY

Many wells flow naturally without artificial stimulation when the well is first drilled. As time goes on and the reservoir gas pressure begins to drop, oil production in the well begins to slow down, and the barrels of oil produced daily begins to drop. When gas especially nitrogen is introduced into the tubing, below the liquid level in the hole, the column of fluid in the tubing begins to weigh lesser than the bottom hole pressure, and the well begins to flow again. [1]

Where gas is available, gas lift is used extensively in producing wells. This added stimulation then allows the wells to flow again. This technique is especially popular for wells that have been flowing marginally, providing a substantial boost in the daily production which can now amount to several barrels.

The importance of using gas lifts include;

To assist a flowing well by increasing their production.

To produce wells that will not normally flow without assistance.

To unload a well that has accumulated heads of water so that, after unloading, the well will then flow naturally.

To produce a high volume of water to be used in water flood.

To remove any solids by back flowing disposal wells.

In this case, Nitrogen gas lift is proposed.

1.2 NITROGEN

With purities of 95-99% acceptable for most offshore operations, Nitrogen gas generation at high pressures and low oxygen levels safely prevents ignition of flammable gases and corrosion of oil field tubular down hole. A colourless, odourless, and tasteless gas, nitrogen constitutes 78.03% of air. It has a gaseous specific gravity of 0.967 and a boiling point of -198° C at atmospheric pressure. The inert nature of nitrogen makes it suitable for offshore applications due to its non-reactive nature with many materials.

The Nitrogen gas is used in well applications to reduce the weight of fluid in wellbores. Nitrogen is pumped through coiled tubing (or gas lift tubing) and discharged at the well perforations. As the nitrogen gas flow up the production casing, it expands and then reduces the weight of fluid in the column, thereby allowing the well to flow.

In setting up the Nitrogen gas lift system, three major sets of components are essential. They are; [1]

Inlet. A supply of dry, high-pressure nitrogen gas.

Downhole. Appropriate downhole well arrangements

Outlet. An appropriate production handling flow measurement facility.

Nitrogen gas compression and distribution; the first step in installing a nitrogen gas lift system is having a very large, satisfactory supply of dry, high-pressure nitrogen gas. If liquid nitrogen gas is to be used, a scrubber must first be installed to remove condensate and water, and a compressor to step the nitrogen gas pressure up high enough for lease distribution and injection. Drip pots also may have to be installed to remove fallout condensate and water that will separate under line pressure. The ideal situation is to pipe the liquid nitrogen gas to a processing facility to remove all liquids. Then the lean or dry gas is piped back to the gas lift lease for compression and injection. A lease distribution system must then supply the gas to each of the gas lift wells. [1]

Control valve. Near to where the line from the compressor is connected to the wellhead, a valve is then installed in the line to open or close the gas to the well. A second choke valve is then installed next to the wellhead to regulate or throttle the gas that is being injected. This valve will be choked.

1.2.1 Housing of liquid nitrogen [7]

Liquid nitrogen should only be stored in containers specifically designed to contain cryogenic fluids. Domestic vacuum flasks should never be used. Dewars and pressurized vessels specifically designed for storage of liquid nitrogen.

A Dewar is a double walled flask with an open neck which freely vents to atmosphere and is not at pressure. A pressurized vessel is generally of larger capacity (over 50 liters) and does not freely vent but has relief valves and vents.

All liquid nitrogen containers should be stored in a:

stable manner and on a sturdy surface; and

position that does not restrict access and egress

position where they are unlikely to be knocked by people or by other equipments

The quantity of liquid nitrogen permitted to be stored in an area depends on the volume and ventilation of the room/area. Areas/rooms with very good natural ventilation are preferable for storage and decanting tasks because splashes, spills and evaporation are less likely to cause an atmosphere with oxygen deficiency. Cryogenic fluids should not be stored or used in an office.

1.3 DRAW BACK OF USING NITOGEN GAS FOR SIMULATING PRESENCE OF NATURAL GAS (e.g. METHANE)

The most important limitation of Nitrogen gas in simulation is the lack of formation gas or the availability of an outside source of the Nitrogen gas. Nitrogen gas for simulating presence of natural gas is not recommended for simulation using viscous crude. Wet nitrogen gas without proper dehydration will reduce the reliability of gas simulation operations.

Another is the effect of Nitrogen gas leakage which can cause asphyxiation or can create an environment for Legionella which is pathogen gram negative bacterium which can also result in death.

2.0 LITERATURE REVIEW

2.1 MULTIPHASE FLOW METER

The need for multiphase flow measurement in the oil and gas production industry has been evident for many years. A number of such meters have therefore been developed since the early eighties by meter manufacturers, research organizations, oil and gas production companies and others. Different technologies and combinations of various technologies have been employed, and prototypes have also been quite dissimilar in design and function. Many lines of development have been abandoned, while a number of meters have become commercially available, and the number of users and application is rapidly increasing. [4]

It is important to measure the fluids produced from oil wells accurately for efficient oil exploitation and production [2]. Typically, field wells produce a complex mixture of gas, oil, water and other components, such as sand, and it is difficult to measure the multi-phase flows (MPFs). The conventional approach is to separate the mixture into individual components, and then measure those separately using single-phase flow (SPF) meters, e.g., orifice plates for gas and turbine meters for oil. There are some specific problems with the required three-phase separators. They include.

The bulk of each of them

 High installation cost

 Considerable maintenance of each of them

Therefore, it is highly attractive to have relatively simple MPF meters, which are capable of measuring the flow rate of each component directly, without separation. During the last decade, considerable efforts have been achieved to develop the Multi phase flow meters. For example, under the UK National Flow Programme, the National Engineering Laboratory (NEL) has assessed the performance of various MPF meters under different flow (in particular gas–oil–water flow) conditions [2]. Currently, there are several commercially available meters, based on different measurement principles. However, all of them have some limitations. Almost all of them are flow-regime dependent and most of them can only deal with homogeneous flows in order to achieve an acceptable accuracy. Flow-mixing devices are often used to palliate this problem because in most cases MPFs are inhomogeneous, especially in horizontal or inclined pipes [2]. MPFMs can provide continuous monitoring of well performance and thereby better reservoir exploitation/drainage [4]. However this technology is complex and has its limitations; therefore care must be exercised when planning installations that include one or more MPFMs.

2.1.1 LIMITATION OF THE MULTIPHASE FLOW METER

The limitations with these devices are that;

They interfere with the flow, causing pressure drops, which are ultimately reflected as an increase in the required pumping power.

Some devices have internal moving parts, which reduce reliability and increase maintenance costs, in particular if the meter is used in a remote location such as the seabed or an unmanned platform.

It will also present operational difficulties if the pipeline needs to be pigged.

Uncertainty of measurement and one main source of this is the fact that they measure unprocessed and far more complex flows than what is measured by single-phase measurement systems.

Possibility to extract representative samples. Whereas samples of the different fluids are readily captured from, for example, the single-phase outlets of a test separator, no standard or simple method for multiphase fluid sampling is yet available. [4]

Others (e.g., some Venturi meters) are designed for upward vertical flows and take advantage of the homogenization occurring naturally in the flows. However, in the case of high gas fractions (above 80%) the degree of homogenization is limited, because gas bubbles tend to concentrate in the centre of the pipe, forming an annular flow pattern.

In the past, oil companies tried to avoid the problems of taking MPF measurements by using gravity-based separators. This allows the liquid and gas components to be measured individually using proven gas and liquid single phase flow meters. Initially, two-phase meters were developed for measuring the liquid components together by a combination of densitometer and Venturi meter. This method is suitable for the production fields, where the use of two-phase separators offers an advantage over three-phase separators in terms of cost and size.

From 1940s to 1970s turbine meters were developed and used for measuring crude oil of normal viscosity and orifice and positive displacement meters for high viscosity. Improvements were manufacturer-driven and resulted in only a marginal impact of the meters on overall oilfield development. Coriolis and ultrasonic meters were developed in the early 1980s and were installed in oilfields in the early 1990s. In the same time period, research into MPF meters was carried out and MPF meters were installed in oilfields. During this period, oil companies primarily drove the research initiatives, and the MPF meters had substantial impact on the overall oilfield developments [2]. Figure 2.1 shows typical arrangements of two approaches to measuring gas–oil–water flows: the conventional method using test separators and on-line measurement.

Full-size image (56 K)

Figure 2.1(a) Conventional MPF metering using separators [2]

2.1.2 CATEGORIES OF THE MULTI PHASE FLOW METER

However in general, commercial MPF meters can be categorized into two types:

Measurement by separation techniques. Due to the difficulty in measuring three-phase components directly, separation techniques are used to segregate gas, oil and water, and then each stream is measured separately. Further development has introduced partial separation, which typically only separates liquid and gas, to improve the accuracy for high gas volume fraction and to reduce the size of MPF meters. An example of an MPF meter using partial flow separation is the Agarcorp MPFM 400.

On-line measurement. The new generation of MPF meters uses direct measurement to reduce the expensive space requirements in an offshore oil platform. They are compact and have non-intrusive sensors. An example of the desirable location of these MPF meters is shown in (b). The ESMER MFM is an example of an MPF meter without using partial flow separation. The latest generation has the flexibility for sub-sea installation. Some systems use homogenizers or flow conditioners to ensure a homogenous regime, thus removing the problem of flow regime dependency.

Gas

1st Stage separator

Production Manifold

MM

MM

MM

Oil

Water

MM=Multiphase meter

From Wells

Figure 2.1(b) On-line Multi phase flow metering [2]

However, the type of Multiphase flow meter that will be used in this test scenario would be a Thermal mass flow meter

2.2 THERMAL FLOWMETER

Instruments for determining the flow rate in a pipe or duct, and must not be confused with ‘hot resistor or hot wire anemometers. [5] They utilize the tracer dilution principle with heat acting as the injection tracer. It is obvious that, other things being equal, temperature rise will be inversely proportional to the flow rate. So mass flow is given by

Upstream temp sensor heating coils downstream temp sensor

Flow C:\Users\u1269376\Desktop\Capture1.PNG

Amplifier

Read out

Bridge for measurement of

Figure 2.2; Principle of thermal flow meter [5]

This type of flow meter is mainly used with gas of relative low pressure and low flow rate.

They can’t be used in high mass flow rate because they will consume an uneconomic amount of energy. Accuracy and initial cost are moderate.

2.3 MULTIPHASE FLOW REGIME

The flow structures are classified in flow regimes, whose precise and accurate characteristics depend on a number of various parameters. The distribution of the fluid phases in space and time differs for the various flow regimes, and is usually not under the control of the designer or operator.

Flow regimes vary depending on fluid properties, operating conditions, flow rates and the orientation and geometry of the pipe through which the fluids flow. The transition that is made between different flow regimes may be a gradual process. [4] [11]

In the laboratory, the flow regime may be studied by direct visual observation using a length of transparent piping [9] which remains the primary focus [11].

Descriptions of flow regimes are to some degree arbitrary, dependent on the observer interpretation.

The main mechanisms involved in forming the different flow regimes are geometry/terrain effects, transient effects, hydrodynamic effects and combinations of these effects.

Transients occur as a result of changes in boundary conditions of the system. This is not to be confused with the local unsteadiness associated with intermittent flow. Closing and Opening of valves are examples of operations that cause transient conditions.[4]

Geometry and terrain effects occur as a result of changes in pipeline geometry or pipe inclination. Such effects can be particularly vital in and downstream of sea-lines, and some of the flow regimes generated in this way can prevail for several kilometres. Severe slugging of the riser is an example of this effect [4].

In the absence of transient and geometry/terrain effects, the steady state flow regime can be entirely determined by fluid properties, flow rates, pipe diameter and inclination. Such flow regimes are seen in horizontal straight pipes and are referred to as "hydrodynamic" flow regimes. These are typical flow regimes that are encountered at a wellhead location [4]

All flow regimes however, can be grouped into separated flow, dispersed flow, intermittent flow or a combination of these.

Dispersed flow is characterized by a uniform phase distribution in both the axial and radial directions. Examples of such flows are bubble flow and mist flow. [4]

Separated flow is characterized by a non-continuous phase distribution in the radial direction and a continuous phase distribution in the axial direction. Examples of such flows are annular and stratified. [4]

Intermittent flow is characterized by being non-continuous in the axial direction, and therefore exhibits locally dynamic behaviour. Examples of such flows are slug flow, elongated bubble, and churn flow. [4]

The worst flow regime in multiphase flow line is slug flow. The slugs can cause a bit of the problems by creating oscillations in flow rate, leading to flooding at the receiving end, increasing the deposits and corrosion. In all, downward flow and pressure build-up inside the pipeline by different ways cause shrinkage in slug flow region.

2.3.1 FLOW REGIME MAPS

The physical geometry exhibited by a multiphase flow in a conduit will be captured by this map. For example, in the three--phase oil/water/gas, free water occupying the bottom of the conduit with oil flowing above and then the gas by gravity.

Flow regime maps are useful tool for getting an overview over which flow regime we can expect for a particular set of input data. Each map is not however, general enough to be valid for other set of data. [12]

Simulating pipes of any elevation involves determining what kind of flow regime we are facing as well as doing calculations for that particular regime.

2.3.1.1 Vertical Pipes

Flow regime maps of the sort shown in figure below are useful when we want to gain insight into the mechanisms creating the flow regimes [12].

The diagram below shows the flow regime map for a three phase flow, one for each phase. The vertical axis contains the gas superficial velocity as a fraction of the total superficial velocities. That particular superficial velocity fraction has been defined so that it becomes 1 for pure gas flow. For pure liquid (oil-water) flow, which corresponds to the straight line in the oil-water plane, the gas fraction becomes zero. Similarly, if the water content is zero, the operation point will be located somewhere on a line in the gas-oil plane, and so on for the zero oil content. Operation points inside the triangle in the figure below will correspond to three-phase flow where are the instantaneous average velocities of gas, oil are and water respectively which is the ratio of the volumetric flow to the pipe cross sectional area

 Three-phase gas-oil-water diagram for horizontal pipes

Figure 2.3; Illustration of steady-state flow regime map for a horizontal pipe

Simplified sets are 3 main patterns that occur in vertical flow:

- Continuous fluid, with gas bubbles / fast particles

- Continuous gas, with drops of liquid / solid particles and liquid film along the walls

- Discontinuous flow: liquid plugs, separated by large gas accumulations

2.3.1.2 Horizontal Pipes [15]

In horizontal flow there are divided up into 3 main types, Segregated Flow, Intermittent Flow and Distributive Flow.

Segregated Flow is divided up into Wavy, Stratified and Annular Flow.

Intermittent Flow is divided up in to Plug and Slug Flow.

Distributive Flow is divided up in to Bubble and Mist Flow.

When gravity acts perpendicular to the pipe axes, phase separation can occur. This then increases possibility of the flow pattern as shown below.

Bubbly flow, like the equivalent pattern in vertical flow, consists of gas bubbles dispersed in a liquid continuum. However, except at a very high liquid velocity when the intensity of the turbulence is enough to disperse the bubbles about the cross section, gravity will then tend to make bubbles accumulate in the upper part of the pipe as illustrated.

In Stratified flow liquid flows in the lower part of the pipe with the gas above it. The interface is smooth. An increase of gas velocity causes waves to form on the interface of stratified flow to yield a Wavy flow. Plug flow is majorly characterized by bullets shaped gas bubbles as seen in vertical flow. However, they still travel along the top of the pipe.

Slug flow, like plug flow, is intermittent. The gas bubbles here are bigger whilst the liquid slugs contain many other smaller bubbles. At large levels of aeration, they are called semi-slug or frothy surges, if the surges do not fill up the pipe completely. However, this might be more correctly considered as part of wavy flow. A continuous gas core with a complete wall film characterizes annular flow [15].

As in vertical flow, some of the liquid can be entrained as drops in the gas core. Gravity then causes the film to be thicker on the bottom of the pipe but as the gas velocity is increased the film becomes circumferentially more uniform.

Figure 2.4 Typical Horizontal Pipe flow regime map [4]

2.3.1.3 Pipes at Other Inclinations [15]

Gas-oil-liquid flow in inclined pipes is characterized by flow patterns similar to those described above for vertical and horizontal flows. For inclined upflow, the range of conditions occupied by a slug type flow, increases considerably starting at even small inclinations from the horizontal. For inclined downflow, the range of conditions for slug type flows then diminishes considerably.

2.4 MASS FLOW MEASUREMENT [5]

There are two alternatives ways to tackle the problem of mass flow rate measurement. One is to design the meter whose response is a function of mass flow rate only, so that the knowledge of the fluid physical properties won’t be necessary. Such meters are called "true mass flow meter".

The other approach is to measure both volumetric flow rate and the fluid density and then compute the mass flow rate.

Where are the mass and volumetric flow rates respectively

A system that does this type of measurement is called the ‘inferential mass flow measurement system’. Many different mass flow meters have been tried in the laboratory and even in the industry. They include wheat stone bridge meter, angular momentum meter, thermal mass flow meter, etc. [5]

In steady state condition, flow velocities vary with the pressure drop, that is,

Where v is the velocity, is the flow coefficient, is the pressure drop, is the density and g is the acceleration due to gravity.

2.4.1 Thermal Mass flow meter

True mass flow meters are truer than the other. There would be no disputing that the thermal mass flow meter is the true mass flow meter.

They are often referred so, but appropriateness of this description in this case is somewhat questionable. Their output depends upon the heat transfer properties of the fluid, so that if for instance, they are calibrated with natural gas having a certain composition, and subsequently the gas composition changes, they would give inaccurate readings.

On the other hand because heat transfer properties of gas don’t change very rapidly with density changes, they can be used within a given gas over a moderate rate in temperature and pressure with too much loss in accuracy. This being the reason why enthusiast refer to them as the true mass flow meter [5]

In General, their performance suffers more from changes in temperature than changes in pressure, and by keeping the gas temperature fairly closely controlled, it would be possible to obtain accuracy approaching over a wide range of flow rates.

2.5 PRESSURE MEASUREMENTS [6]

Atmospheric pressure is held constant at

Pressure can be used inferentially to measure variables such as flow and level. It is intimately bound up with the flow parameter [6]. Generally speaking, it is impossible to have fluid without pressure, therefore giving it the ‘motive power’ behind flow. In the case where flow occur between two points under gravity influence, we do have a case of high and low pressure head due solely to the position difference between the two pressure point, will cause the material to be moved further and faster than it would under a low value of this parameter.

2.7 AIM/ OBJECTIVES

This report would be concerned basically with the design modification that must be made on the University of Huddersfield flow facility, currently an oil well facility, which would then be extended to a three phase oil-water-gas facility using Nitrogen and also the instrumentation and control system to be installed accurately to measure the volumetric flow rate using a multi-phase flow meter of the Nitrogen in the working section of the flow facility.

All these design modification that would be made on the existing flow facility would definitely depend on the safety issues involving the use of Nitrogen gas. The major objectives of this project include

Designing the source of Nitrogen

Housing of the Nitrogen during project process

Designing the room/lab where the project will take place

Eliminating uncertainties and ensuring calibration of the flow meter

Design of the piping material to be used

Designing the Length and Area and diameter to be used

Designing of the control valve and type to be used

Designing the Pressure drop that will occur across the pipes

Nitrogen gas pressure regulation control

Design of the PID controller and flow metering

Ensuring flow at all time during the process

Also to determine the various flow regime maps that can occur for the different piping arrangement positions

Modifications that would be made to the separation tank to prevent leakage

3.0 METHODOLOGY FOR ANALYSING AND DESIGNING THE FLOW PROCESS

3.1 DESIGNING THE SOURCE OF THE NITROGEN GAS [16]

Assuming using just two nitrogen gas cylinders with the two nitrogen cylinder connected in manifolds. Nitrogen gas is supplied from the first nitrogen cylinder connection manifold to a first pressure self-regulating valve to reduce the high gas pressure and then distributed to second pressure self-regulating valve to supply gas through the stainless steel pipe connected to it.

The nitrogen gas pressure is modulated by first pressure self-regulating valve and second pressure self-regulating valve to maintain proper pressure.

Also, the pressure of the nitrogen gas downstream of the first pressure self-regulating valve is monitored by the pressure transmitter for the following purpose.

To monitor any leakage of nitrogen gas in no operation of nitrogen gas supply system

To monitor the pressure of the nitrogen downstream of the first pressure self-regulating valve

3.2 DESIGNING THE HOUSING THE NITROGEN GAS [16]

Do not allow storage area temperature to exceed 50°C (12°2F). Do not store in a confined space. It would be stored just outside the Lab with a cage with about 2000mm tall about 1000mm wide comprising of about 4 cylinders.

Nitrogen distribution system consists of nitrogen gas cylinder connection fed by rack mounted, high pressure portable cylinders complete with 1st pressure self-regulating valve with pressure indicator and second pressure self regulating valve with pressure indicator, pressure transmitter, safety valve, distribution piping and valves.

Stored cylinders should be periodically checked for general condition and leakage. Protect cylinders stored in the open against rusting and extremes of weather. Cylinders should not be stored in conditions likely to encourage corrosion. Cryogenic containers are equipped with pressure relief devices to control the internal pressure.

Store in a well controlled environment away from spontaneous weather change. This will the prevent the nitrogen from undergoing drastic changes in its temperature or pressure

3.3 DESIGNING THE ROOM/LAB FOR THE PROJECT PROCESS [17]

Where liquid nitrogen is used in laboratories with limited or no natural ventilation, only limited quantities can be safely used. If it is necessary to store and use larger quantities of liquid nitrogen however, a low oxygen sensor may be needed.

A low oxygen sensor will alert persons when there is an oxygen deficient atmosphere in the room. Atmospheric oxygen depletion sensors must be installed in the relevant areas or the ventilation must be improved. Avoid the use of wide-necked, shallow vessels to prevent excessive evaporation and the possibility of oxygen depletion.

The risk of asphyxia must be assessed first, wherever liquid nitrogen is to be used or stored, taking into account the volume present in relation to the room volume, the likelihood of leakage or spillage, the normal evaporative losses that occur with liquid nitrogen use and any ventilation arrangements.

Keep in a well ventilated room [17]

The room should not be a confined area, to help exhaust any nitrogen gas off-gassing from the container.

A non ventilated room can rapidly become oxygen deficient.

It is also recommended that the building that the nitrogen is stored in has an exhaust ventilation system to outside the building. All lab buildings should have this system.

Do not leave Dewar containers uncovered at any point in time, but make sure to have an exhaust system

If the container is completely covered, the pressure could increase rapidly to dangerous levels, so exhaust is definitely required. If left completely uncovered, the liquid nitrogen will evaporate much faster.

The installation of the oxygen monitoring device will rely on the manufacturer’s specifications and recommendations. Some of these requirements may include, but not be limited to any of the following:

1) Installing the sensor device close to an area where leakage would most likely occur;

2) Placing the sensor device at the proper height depending on the gas density;

3) Ensuring that the sensor device’s display is accessible;

4) Performing a leak test of the oxygen monitoring devises’ sample lines, system components and fittings as per the manufacture’s specification, a low oxygen alarm shall be installed along with the monitoring device to alert persons in the surrounding area of a hazardous condition. This monitoring device should also be interlocked with the building automation system (BAS). Where applicable, the device shall also be interlocked with an emergency exhaust fan or system that is located at the monitored location. An alarm will then trigger emergency ventilation of the enclosed space. Alarms that are installed during new construction, or building alteration, should include both visual and audible warnings to notify occupants. [17]

3.3.1 CALIBRATION OF THE OXYGEN SENSOR

Calibrations are performed to verify the accuracy of the oxygen sensor, which is the main component of an oxygen monitoring device. There are basically three different types of calibrations: daily, initial and interval. Initial and interval calibrations are performed by the manufacturer or manufacturer’s representative. All calibrations records must be kept, preferably in a designated notebook located near the alarm (readily available).

Initial Calibration

An initial calibration must be performed by the manufacturer or manufacturer’s representative when oxygen monitoring device and/or new oxygen sensor is installed.

Daily Calibration Checks

To ensure the unit in functioning properly enough, the device must be ensured to be checked daily with a response gas.

This check does not require the unit to be adjusted, but that the observed readings of the device are acceptable. Both a zero gas and span (response) gas, if applicable, should be used during this check. Some of these devices have the capability to perform this function automatically.

Interval Calibrations

These calibrations should be performed by the manufacturer or manufacturer’s representative either every 6 months or per the recommendation of the manufacturer, whichever is more frequent. A more frequent calibration schedule may be necessary if readings are out of range.

The daily calibration check should still be performed.

The building automation system and emergency exhaust fan, where applicable, should also be verified as operational during the interval calibration. In additionally to a leak check of the sample lines, system components and fittings should also be performed at the interval calibration.

3.4 FLOW METER UNCERTAINTIES AND CALIBRATION [4]

In order to use a MPFM in a specific application it is required that the meter has been evaluated with respect to combined expanded measurement uncertainty for the various measurements it will perform.

Such an uncertainty evaluation must include the uncertainties of the quantities input to the MPFM and the functional relationships used. This evaluation should also include the implementation of the models and measurement procedures in the MPFM, in order to consider the meter as it really operates. Uncertainty calculations should be performed according to the principles of the ISO Guide to the expression of uncertainty in measurement (1995).

MPFM should be capable of continuously measuring the representative phases and volumes within the required uncertainties. The flow rates will vary over the lifetime of the whole flow facility process, and it is important to ensure that the MPFM will measure with the required uncertainty at all times. Alternatively, the MPFM may have to be exchanged at some later stage in the production life. This will be an important issue to consider when deciding upon the sizing of the MPFM.

Measurement uncertainties can be specified both as absolute or relative uncertainties, and for MPFMs: [4]

• Flow rates are normally specified with relative uncertainties, also

• Phase fractions are normally specified with absolute uncertainties.

Careful selection of the type of MPFM is not the only important factor. In addition the installation must include adequate auxiliary test facilities to allow calibration (and if needed adjustment) and verification during operation to ensure confidence in the measurements over the whole process flow.

If such periodic verification of the MPFM is not carried out, increased measurement uncertainty must be expected. Simple testing may be performed with a static measurement. [4]

3.5 HIGH-NITROGEN STAINLESS STEEL PIPE WITH HIGH DUCTILITY, HIGH STRENGTH, AND EXCELLENT CORROSION AND HEAT RESISTANCE

Provided is a novel high-nitrogen stainless-steel pipe which is not obtained with any conventional technique, the stainless-steel pipe having high ductility, high strength, and excellent corrosion and heat resistance. Ductility gradually increases toward around the centre of the cross-section of the pipe as the Nitrogen concentration decreases. Furthermore, the steel pipe is strengthened by slight plastic working to give a high-nitrogen austenitic stainless-steel pipe having high ductility, high strength, and excellent corrosion and heat resistance. A plurality of the thus-obtained high-nitrogen austenitic stainless steel pipes of the same quality are disposed one over another so as to result in dimensions. This stainless-steel pipe or hollow material can have large or small sizes and can be of various kinds (http://www.freepatentsonline.com/y2013/0004883.html)

Note that the absolute roughness coefficient of Stainless steel used is 0.015 with length 5meters

3.6 DETERMINIG THE AREA AND DIAMETER OF THE PIPE

From ideal gas equation,

3.7 CONTROL VALVE DESIGN [6]

A control valve dissipates energy and energy dissipation is the sole purpose of its design. It should therefore be important to consider the cost of energy in evaluating the effect a the control scheme on the overall profitability and running of the whole process.

3.7.1 TYPICAL INDUSTRIAL CONTROL VALVE DESCRIPTION [6]

There are several different types of control valves, with differences being confined to the shape of the plug and manner in which the device is operating.

http://www.valvesungo.com/UploadFiles/Electric%20control%20valve1.jpg

Figure 3.1; Typical Industrial control valve

The Body-It is the part of the valve through which process fluids passes and it is here where the fluid is also manipulated. Since the process fluid is in intimate contact with the body, same process condition of the fluid would be subjected to the body which would then determine the material choice to be used

Connections-The means by which valve is attached to the process line are called connections, which form an integral part of the body. The type of connection selected will depend on the service to which the valve would be put to use.

Plug-They are the contoured end of the stem, by means of the flow of the process fluid is regulated, which can be of different shapes such as cylindrical, wedge, spherical, etc. The contour of the plug determines the flow characteristics.

Stem-It is a part of the plug that has the linear sliding movement. Some stem can be rotational, like the ball valves

Seat-It is in the form of ring having its inner face closely following the contour of the plug and into which the plug itself fits. It should be made clear that the nearer the plug is towards the seat, the smaller will be the flow, and the flow would be greater when the plug is further away from the seat.

Yoke-It is a support member for the top works or drive mechanism of the control valves. For most valves, it is a metal casting, roughly in the shape of a tall box without the back and the cover, when assembled unites the top works and the body.

Actuator Stem-It is a short metal shaft, of which one end is fixed to the valve drive mechanism and the other end to the valve stem. It is the means by which the movement of the valve motor is transferred to the valve stem and plug. The valve and the actuator stem are joined via a turn buckle assembly, which provides the means of adjusting the stem travel. None of the part of this assembly should come in contact with the process fluid, and does not create room for the material compatibility problem

Actuator Spring-It is a compression mechanical spring or could be an extension spring depending on the failure mode of a calculated force and spring rate against which the valve motor works to position the plug. Since majority of the valves are operated pneumatically, the physical location of the spring with respect to the actuator diaphragm and the pneumatic inlet connection will determine the direction of the stem travel when either the control signal is removed or the valve is taken out of service.

Actuator-Usually referred to as the valve motor and it’s the means by which the control signal is made to act on the process to reduce any errors. It could be a diaphragm motor, a cylinder actuator (uses pneumatic or hydraulic power), a squirrel cage electric box, or a disk type linear electric motor that concerts rotary to linear motion of the stem.

Majority of actuators are pneumatically operated, due to their cheap cost, but one major advantage if this type is that it makes very fine changes in movement obtained by small changes of the pneumatic signals, which are the most difficult signal to replicate electrically.

Electric actuators are equally available but are expensive, also heavy on power usage, and therefore make it a limited suitability in hazardous industrious environment.

Stem connector- It links two separately assembled parts of the control valve, top works and the valve body, including the stem- to make a complete functional unit. The connector, which must fulfil two vital function which are, to be firmly fixed but yet, easily dissembled when necessary is usually a screw threaded turn buckle with an additional locking pin, with the turn buckle providing some adjustment compatibility and also the locking pin ensuring secure positioning.

3.7.2 PRESSURE DROPS ACROSS CONTROL VALVES [6]

It is one of the most important aspects of control valve. Consider the figure below

Isolating valves (manual)

Control valves

Low Pressure receiver

High pressure source

Bypass valve

Figure 3.2; typical control valve arrangement in a process line [6]

Assuming that high pressure source has an output characteristic that approximates that of a pump, in that for maximum flow, the outlet pressure is lower than that of the minimum flow. This is so because at low flow, the velocity is lover, so are the losses, and as a result, the outlet pressure would be higher.

3.7.3 REASONS FOR CONTROL VALVE FAILURE AND HOW TO OVERCOME THEM [6]

When routine maintenance of the control valve is carried out, the control valve become very reliable and performs their assigned task very well. However like other instrument, they occasionally fail, but when failure is premature, then the cause maybe investigated and corrected. It can be due to;

Cavitage damage

Erosion of trim

Corrosion

Resonating plug

Wire drawing of the trim, i.e. actual cutting away of a silver of material like swarf when machining.

Excessive stem packing leakage

To minimize these failures, [6]

Select a valve with a low pressure recovery trim or install a secondary flow restrictor, or relocate the valve to a more favourable position

Wet steam, but most often hot steam condensates, which eats away the carbon steel of the valve body. Stainless steel or alloy steel should then be used for the valve body

Use hardened trim or angle valves. Angle valves are suggested for flashing condensates at the inlet of condenser, and erosive fluids. Fluid flow should be in the direction that does not cause the valve to plug to lift.

Reversing flow direction at times eliminates some specific problems

Make better selection of valve construction material with the aid of corrosion table

Excessive stem packing leakage causes are

Valve has loose packing flange nut when shipped from manufacturer

Hot fluid service solution is to retighten packing after valve has been warmed up

Rotating the actuator before or without loosening the stem packing, or unstable control over extended period causing wear which then results in leakage

Higher coefficient of expansion of packing compared with the other material used

Total effective packing length less than full length of stem travel, it must be greater

Stem misalignment

Various types of valves include Rotary-plug valve, butterfly valve, ball type valve, diaphragm type valve, etc

3.8 DARCY FRICTION PRESSURE LOSS EQUATION [15]

There are three sources of pressure drop:

Hydrostatic Gradient which arises from the density of the multi-phase column of fluids. It is calculated from a knowledge of the liquid hold-up (the proportion of the flowing area occupied by liquid), and the densities of the phases. It is proportional to the cosine of the deviation, being zero in a horizontal pipe. Most correlations use a flow-regime map to determine the type of flow, and then use a particular correlation for the flow regime concerned to determine hold-up.

Friction Gradient arising from the drag of the fluids on the walls of the pipe. This is calculated in a specific way for each correlation, but generally uses the concept of a Friction Factor diagram (such as Moody’s) to calculate the friction factor as a function of the Reynolds Number and pipe roughness. The friction factor is used to calculate the friction pressure gradient.

Acceleration Gradient arising from the increasing kinetic energy of the fluids as they expand and accelerate with decreasing pressure. This term is often negligible, but is always included in these correlations.

One effective way to calculate this pressure drop in the pipe and to give room for compensation when the pressure drops in the pipe is through calculating frictional head loss (or pressure drop) in pipe flow which is related to the friction factor and flow velocity by the Darcy Weisbach equation. Reynolds number is needed in order to find friction factor value. Fully grown developed turbulent flow is needed in order to use the friction factor equation for pipe flow coefficient calculation. The Darcy Weisbach Equation applies to fully developed, turbulent pipe flow. Remember that pipe flow will be turbulent for a Reynolds number greater than 4000. [13]

[15]

= head loss due to friction

Where frictional pressure drop

L = pipe length

D = pipe diameter

ρ = fluid density

V = average flow velocity of fluid (= Q/A) where Q is volumetric flow and A is pipe cross sectional area

f = friction factor which is equal to for smooth pipes and -2 for fully rough (wholly turbulent flow) and high Reynolds number

ε = an empirical pipe roughness

= Dynamic viscosity

For laminar flow (Re < 2100): f = 64/Re

For smooth pipes and -2 for fully rough (wholly turbulent flow) and high Reynolds number

-2

-2

Pressure drop in the pipe

3.9 PRESSURE REGULATION METHOD

The best way to monitor and regulate the pressure coming from the nitrogen cylinder is by using the pressure regulator which is a valve that automatically cuts off the flow of the gas at a certain pressure [8]. The primary function of any gas regulator is to match the flow of gas through the regulator to the demand for gas placed upon the system. At the same time, the pressure regulator must maintain the system pressure within certain acceptable limits [10]. The regulator is placed upstream of the control valve or that is varying its demand for gas from the regulator.

If the load flow decreases, then the pressure regulator flow must also decrease, otherwise, the regulator would put too much gas into the system and the pressure would increase. On the other hand, if the load flow increases, then the regulator flow must also increase in order to keep the pressure from decreasing due to a shortage of gas in the pressure system. The following steps should be taking [9]

Inspection [9]

Be certain that the materials of a pressure regulator are chemically compatible with the Nitrogen gas service before installation. Gas regulator should be inspected for the proper valve inlet connection and note the ranges of the pressure gauges. Examine also the physical condition of the regulator including its fittings and thread. Also remove any dust or dirt from the gas regulator or cylinder valve with a clean cloth

Installing a Gas Regulator [9]

The gas pressure regulator should be securely installed on the cylinder valve using the proper wrench and without forcing the connection. Do not use, pipe thread, pipe dope or Teflon tape on valve connections and never use valve connections that leak. Adapters to one valve connection from another valve are not to be used to connect equipment to a high-pressure cylinder. The gas pressure regulator adjusting knob should be turned in the full counter clockwise or closed direction. This needle valve should be closed by turning its adjustment knob in the full clockwise direction. Also, the downstream equipment connection can then be made to the gas regulator output needle valve.

Operating a Regulator [9]

The operator, protected by safety glasses, should ensure to stand to the side of the gas cylinder opposite the regulator and slowly open the cylinder valve until the high-pressure gauge indicates the full cylinder pressure.

The regulator output needle valve can be opened after it is certain that all downstream equipment is rated for pressures above the maximum regulator outlet pressure.

Open the gas regulator by turning its adjustment knob clockwise until the desired output pressure is indicated on the delivery gauge. After this setting has been made, inspect the delivery pressure gauge to make certain that the gas regulator is providing a constant and stable output pressure.

Check the system for leaks by closing the downstream equipment valve, setting the regulator pressure, closing also the cylinder valve and turning the regulator adjusting knob one turn counter clockwise. A decrease in the high-pressure gauge would indicate a leak in the fitting where the valve connects to the cylinder or high-pressure gauge. Also, a decrease in the low pressure gauge indicates a leak in the outlet fitting, the low pressure gauge or the downstream equipment connection. Check for the exact location by using the appropriate leak detection instrumentation or methods. Also, a decrease in the high pressure gauge occurring concurrently with an increase in the low pressure gauge indicates a leak in the regulator seat. The regulator must now then be repaired or returned to the manufacturer for servicing.

Close the cylinder valve when the cylinder is not in use. When the downstream equipment is also not being used, close the cylinder valve and then open the equipment valve to remove all pressure from the regulator. Close the valve of the equipment and then release all tension on the gas regulator adjusting knob by turning it in the full counter clockwise direction.

3.10 BASIC ELEMENT OF A CONTROLLER

As demand for better, cheaper and more varied materials increases, so does the complexity of modern industrial process to satisfy the customer demands [6]. This result in an increase number of process parameters to be monitored and controlled too much closer tolerance that it has ever been.

A very easy general definition of controller might be given as a device or a person that is capable of maintaining conditions or other persons within acceptable predefined limits. For any controller to be able to perform as much, it must fulfil the following four requirements and functions.

Must have an input in the form of measurements

Must have means for generating and setting a desired value(set point)

Must have ability to compare the measurement with the desired value and then produce any error difference between them.

Must be capable of producing an output of sufficient magnitude and direction to correct any deviations from the desired value that may occur.

The controller can be of two types [6]

A simple on and off controller action device with only two control states (ON/OFF). No other states exist in between

The other is the three term controller (PID)

Process

Comparator

Measuring unit

Proportional

Output value

Integral

v

Auto

Derivative Manual

Signal generatorFrom external source

Set point

Figure 3.3; PID Controller Schematic [6]

Starting at the input or measurement, i.e. signal coming from the sensor or transmitter, which is representing the variable being measured. The input signal would be converted into a standard form that can be manipulated by the controller and it’s assigned a definite value. This is called scaling [6]. It is important to scale when using an analogue measurement instrument, for the transmitted signal of the measuring instrument must be made to correspond to the process variables they represent and also to each other.

The conditioned scaled signal is then applied to the comparator, which is really a subtracting unit that takes the difference between the set point values and measured value producing an error signal, meaning that a measurement above the set point gives positive error which will require decreasing the output or a measured value below the set point giving a negative error and would require increasing the output.

The error signal is then applied to the control unit which produces appropriate controlled output to reduce the error. To achieve the necessary control output, the control unit would make use of the following three actions combined

Proportion

Integral

Derivative

3.10.1 CONTROLER SPECIFIC ROLES [6]

Proportional Control Action

This action produces an output that is proportional to the error and can be expressed as,

Where

It is assumed that for a small range of variation about a mean working value, the component units of a system behave in a linear manner. Hence under steady state condition, each position, M, of the correcting element correspond to a discrete value of controlled condition applied.

Where M is the correlation being applied and k is the constant of the plant and the correlation unit monitor and k1 is the proportional action factor of the controller.

Proportional relationship between output and error implies that for each value of Er, the controller will produce a correlation factor, M. If another disturbance occurs to cause deviation, controller will apply a correction factor of.

The effect of the disturbance will be produced by M, and once the signal has been restored to their original values, will be zero. However, if the disturbance result in a permanent change, desired value will not be attained but new equilibrium value will be achieved.

The new value is called the control point, and the difference between the desired value and the control point is called the ‘offset’.

The value of the offset can found by considering the deviation value which would have occurred without control. Let call this value.If the controller reduce this actual deviation to the value of the offset, which is, say,, then correlation applied would the result to

But

From this equation, as increases, offset decreases for a given value of. In practice, value is very small. So that significant offset, dependent of the value of, for load changes can be anticipated, and some other means have to be found to reduce this offset which can be achieved by Integral control action

Integral Control Action [6]

This action produces a signal component in the controller output that is proportional, not only to the value of the derivation action but also the integral, over the time it persists. Mathematically,

As long as any deviation exists, the integral action signal will continue to increase and as a result, deviation due to any load change must eventually be reduced to zero. If is the integral action factor of the controller, v is then

If the input error signal, to a proportional plus integral controller remains constant for a time, the contribution of the proportional action to the output, v will remain constant at, but the integral action contribution will increase from zero to

At any particular point in time, t

And if is held constant

Derivative control action[6]

It provides a signal to the controller output, proportional to the rate at which the derivation changes. If increases from zero to a constant rate after equilibrium, the derivative action will immediately provide a contribution of the two action and will be equal to

Where is the derivative constant of proportion

Derivative action is never used on its own. So, we convert it to a proportional plus derivative controller which will make proportional action increase continually as increases and at some time, t, the contribution of the two actions will be equal.

From which

Combining all three actions [6],

So for proportional + integral + Derivative

3.11 FLOW INDICATOR [5]

They are cheap and are easy to use, that shows the glance whether fluid is flowing or not. They usually have some sort of transparent section, containing a solid object that moves when flow occurs. It may be hinged flap or a ball which rises, or a spinner that rotates.

3.12 MODIFICATION OF SEPARATION TANK TO PREVENT GAS LEAKAGE

If a leak detector is not available, use the following methods to locate leaks:

Cover the suspected leaks with a low vapour pressure sealing compound such as Apiezon Q, or Duraseal. Do these while pumping on the equipment and monitoring the pressure. A sudden decrease in pressure indicates that a leak has been covered. Repair leaks permanently as previously directed.

If the leak is large, causing pressures in the Torr range, use a fast acting thermocouple gauge in conjunction with a probing medium such as Freon or helium. Position the vacuum gauge head downstream from the suspected leak and pump. When the pressure has been reduced so that the gauge may be used, apply probing medium to suspected leak areas. If the probing fluid is directed at the leak or an area close to it, a sudden change in pressure will occur.

Cover the suspected leak with plastic sealing compound and continue leak checking until desired pressure is obtained. [18]

If leak checking fails, disassemble and remake all demountable joints and connections using new gaskets or vacuum sealing compound such as Loctite 515. [18

3.13 CONTROL VALVE

3.13.1 HOW TO SIZE A GAS CONTROL VALVE [14]

Sizing of a control valve means to select a valve with the correct size orifice to allow good control of flow rate within a required range.

There are other important factors to consider when selecting a control valve, such as valve characteristics and valve type but this article will concentrate on valve sizing.

3.13.2 STEPS TO ACCURATELY SIZE A GAS CONTROL VALVE [14]

Specify the required design flow rate

Specify the pressure drop that would be allowed across the valve

Choose a valve type and also, body size from the manufacturers’ specification

Determine the first estimate of the piping geometry factor and pressure drop ratio factor

Determine also if the flow through the valve will be sub-critical or critical

Calculate the effective pressure drop ratio through the valve

Calculate the expansion factor

Then calculate the first estimate of the required valve flow coefficient

Check that the calculated valve flow coefficient is less than the actual valve flow coeficient of the selected valve (re-select suitable valve from manufacturers’ tables if required)

Check that valve control range is OK

If the Cv (valve flow coefficient) and control range are suitable the valve is correctly sized.  If not choose another valve and repeat the sizing procedure from Step 3

Control valve sizing for a particular duty is governed by the required flow rate the valve must pass and the pressure drop that can be allowed across the valve.

For preliminary estimates of control valve size it is usually OK to assume that the piping geometry factor is 1. [14]

The equation given below is used for calculating the for a gas control valve using metric units is given below:

[14]

3.13.3 EFFECTIVE PRESSURE DROP [14]

The effective pressure drop across a gas control valve depends on the properties of the gas flowing through the valve and the valve design. If the pressure downstream of the valve is lower than a critical value, the flow across the valve will be choked.  Choked flow can also be known as critical flow.

The flow is sub-critical if:

Where P2 is the downstream pressure after the pipe

For critical flow

Where

Pressure ratio for critical flow also depends on the system geometry.

Where the pressure drop ratio factor is the pressure drop ratio required to produce critical flow through the valve when Fk is equal to 1. That is,

3.13.4 EXPANSION FACTOR, Y [14]

The expansion factor accounts for the expansion of gas flowing through the valve as the pressure reduces from inlet to outlet.  The expansion factor is then the ratio of flow coefficients for a gas to that for a liquid at the same Reynolds number.

The expansion factor must be less than or equal to a value of 0.667.  The equation below defines the expansion factor:

3.13.5 PIPING GEOMETRY FACTOR, [14]

The piping geometry factor is an allowance for the pressure drop associated with fittings that may be connected directly upstream and/or downstream of the valve. If no fittings are connected to the valve, the piping geometry factor would then be 1.

The piping geometry factor is often listed in valve manufacturers’ specification.  Alternatively, it can be calculated using:

Most commonly, the fittings connected to a control valve are downstream and upstream reducers.  In this case the sum of the fittings factors for the reducers is: [14]

3.14 GENERAL INSTRUMENT CAUTIONS [6]

General consideration when instruments system is being designed to obtain meaningful final results include,

When smart or intelligent transmitter are used in a control loop to provide measurements and are rearranged or recalibrated from a control room, measurements signal to the associated controllers will go inactive and might result in process control loss for that duration.

Ensure that measuring device signals are true representative of actual process being measured.

Some process demand a non linear characteristics in the controlled output

3.14.1 INSTALLING THE FLOW DEVICE [6]

Straight pipe run- As a general rule, ensure that all primary flow devices have long, straight lengths of pipeline both up and downstream of the instrument its self (about 15 to 20 pipe diameter upstream and 7 t0 10 pipe diameter downstream)

Minimizing process noise-Every effort should be made to eliminate process noise from all existing turbulence creating equipment, e.g. pump, valves, pipe bend, pipe fitting

3.14.2 INSTALLING PRESSURE DEVICE [6]

Need for consistent engineering units, because there are various unit to choose from

Using a snubber in eliminating any fluctuating measurements in pressure

3.14.3 INSTALLING TEMPERATURE DEVICE [6]

Making use of thermowells which are often fitted to the temperature sensors

Installing the temperature devices with thermocouples (self generating transducers comprising two or more functions between dissimilar metals)



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